Also by EU-China Energy Cooperation
Platform Project
2020
EU China Energy Magazine Spring Double Issue
EU-China Energy Magazine Summer Issue
中欧能源杂志夏季刊
EU-China Energy Magazine Autumn Issue
中欧能源杂志秋季刊
EU-China Energy Magazine 2020 Christmas Double Issue
中欧能源杂志2020圣诞节双期刊
2021
EU-China Energy Magazine 2021 Spring Double Issue
中欧能源杂志2021春季双期刊
EU-China Energy Magazine 2021 Summer Issue
中欧能源杂志2021夏季刊
EU China Energy Magazine 2021 Autumn Issue
中欧能源杂志2021秋季刊
EU China Energy Magazine 2021 Christmas Double Issue
中欧能源杂志2021圣诞节双刊
2022
EU China Energy Magazine 2022 February Issue
中欧能源杂志2022年2月刊
EU China Energy Magazine 2022 March Issue
中欧能源杂志2022年3月刊
EU China Energy Magazine 2022 April Issue
中欧能源杂志2022年4月刊
EU China Energy Magazine 2022 May Issue
中欧能源杂志2022年5月刊
EU China Energy Magazine 2022 June Issue
中欧能源杂志2022年6月刊
EU China Energy Magazine 2022 Summer Double Issue
中欧能源杂志2022年夏季雙刊
EU China Energy Magazine 2022 September Issue
中欧能源杂志2022年9月刊
EU China Energy Magazine 2022 October Issue
中欧能源杂志2022年10月刊
Digest of the Handbook on Electricity Markets - China Edition
Digest of the Handbook on Electricity Markets - International Edition
电力市场手册 （精华版）- 中国发行
电力市场手册 （精华版）- 国际发行
EU China Energy Magazine 2022 November Issue
Joint Statement Report Series
Electricity Markets and Systems in the EU and China: Towards Better
Integration of Clean Energy Sources
中欧能源系统整合间歇性可再生能源 - 政策考量
Supporting the Construction of Renewable Generation in EU and China:
Policy Considerations
中欧电力市场和电力系统 - 更好地整合清洁能源资源
支持中欧可再生能源发电建设: 政策考量
ENTSO-E Grid Planning Modelling Showcase for China
ENTSO-E 电网规划模型中国演示
Accelerating the Incubation and Commercialisation of Innovative Energy
Solutions in the EU and China
加速中欧创新能源解决方案的孵化及商业化
Comparative Study on Policies for Products’ Energy Efficiency in EU and
China
中欧产品能效政策比较研究
欧盟和中国的能源建模报告
Integration of Variable Renewables in the Energy System of the EU and
China: Policy Considerations
Table of Contents
Also By EU-China Energy Cooperation Platform Project
Letter from the Team Leader
1. Never too early to prepare for next winter
2. The 5th EU electricity market reform: a renewable jackpot for all
Europeans package?
3. What can China’s electricity markets draw from international
experience?
4. China’s power system needs to modernise
5. 3 ways clean hydrogen projects can boost their chances of securing final
investment decisions
6. News in Brief
7. Featured Publication
Sign up for EU-China Energy Cooperation Platform Project's Mailing List
Also By EU-China Energy Cooperation Platform Project
Letter from the Team Leader
Dear all,
Welcome to the November 2022 issue of the EU-China Energy Magazine!
During EU-China Climate Diplomacy Week earlier this month, ECECP
organised a three-day virtual Expo: 15 European companies showcased
their innovative clean energy solutions in renewable energy, energy
efficiency, buildings, electricity grids and storage. At the time of writing,
there were 1 300 visits and nearly 20 000 page views from China, the EU,
the US, the UK, Japan and Russia. It is still possible to visit the virtual
booths, while interested parties can contact the companies directly.
The Digest of the Handbook on Electricity Markets, in both Chinese and
English, was launched at the Expo’s opening ceremony. The original
Handbook on Electricity Markets - a 650-page encyclopaedia of the global
electricity market, -was written by some of the most brilliant thinkers in the
field. ECECP commissioned the Digest so that the Handbook’s key points
are accessible to busy decision-makers. The Digest, in English and Chinese,
is available for free download on the ECECP website.
A Chinese translation of the original Handbook on Electricity Markets is
now under way and will be available in the spring of 2023.
Interviews with exhibitors, political representatives and other energy
experts are available on our website.
The ECECP magazine includes an article that offers a brief overview of the
key points raised in the Handbook and in discussions held at the Expo.
Other articles in the issue include a focus on the energy supply challenges
looming in the winter of 2023-24; Leonardo Mees of the Florence School of
Regulation looks forward to a time when power consumption can be
managed without recourse to emergency measures; a summer drought in
China has highlighted the need for power market reform in the country; and
the World Economic Forum looks into ways to accelerate investment into
hydrogen power.
This month, our designer has been laid low by Covid and we were not able
to publish as scheduled. We wish her a speedy recovery. As always, I would
like to thank our hard-working editors, Daisy Chi and Helen Farrell.
I hope you enjoy reading this issue.
Flora Kan
ECECP Team Leader
1. Never too early to prepare for next
winter
As winter approaches, a combination of
favourable LNG market dynamics, robust
pipeline deliveries from non-Russian suppliers,
lower demand, and policy actions has given
Europe a chance to sidestep some of the worst
immediate impacts of Russia’s steep cuts to
natural gas deliveries.
Russia’s pipeline gas deliveries to the European Union halved in the first
ten months of 2022 compared with last year’s levels. The decline in
absolute terms was 60 bcm, the equivalent of over 10% of the global LNG
trade. The steep decline in Russian gas supplies coincided with multi-year
lows in European hydro and nuclear power output (down by 20% and 16%
year-on-year, respectively), putting huge pressure on European gas markets.
Gas prices on the Dutch Title Transfer Facility (TTF) – a leading European
gas hub – averaged over EUR 130/MWh (USD 40/MMBtu) year-to-date,
almost eight times the 5-year average between 2016 and 2020. The all-time
high prices attracted record LNG inflows to the European Union and the
United Kingdom, rising by 65% or over 50 bcm year-on-year in the first ten
months of 2022.
Gas demand in the European Union and the United Kingdom in the first 10
months of 2022 was down by an estimated 10%, or over 40 bcm, compared
with the same period a year earlier. This was mainly the result of lower
consumption across the residential, commercial and industrial sectors, but it
also includes some efficiency gains and behavioural responses to higher
prices. It also reflects demand destruction, particularly in gas-intensive
industries.
Non-Russian pipeline supplies to Europe increased substantially. Pipeline
deliveries from Norway rose by 5% (5 bcm) and flows from Azerbaijan via
the Trans Adriatic Pipeline surged by close to 50% (3 bcm) year-on-year in
the first ten months of 2022. In both cases, export infrastructure is running
close to nameplate capacity. Algeria increased its pipeline supplies to
Europe by over 10% (or 3 bcm) on available export routes in the first ten
months of the year, and has some limited upside.
Strong European demand for LNG led to a reconfiguration of global LNG
flows as increases in LNG supply (23 bcm) were not sufficient to meet
Europe’s rapidly rising LNG imports. Higher LNG flows towards Europe
were enabled in part by China’s LNG imports falling by 20% (or 19 bcm)
year-to-date as it drastically reduced spot procurements. Europe’s thirst for
LNG also disrupted gas and electricity supply in more price-sensitive
markets, including in South Asia.
Mild weather, healthy storage levels and strong
LNG supply have led to a significant fall in some
natural gas price markers
The combination of higher non-Russian gas imports and lower demand was
instrumental for Europe to offset Russia’s gas supply cuts and enable a
near-record build-up of storage levels. Storage injections were 22%, or 13
bcm, above their 5-year average in 2022. At the beginning of November,
EU storage sites were close to 95% full – well above the European Union’s
80% target and well-aligned with the IEA’s 10-Point Plan to Reduce the
European Union’s Reliance on Russian Natural Gas.
Unseasonably mild weather in October reduced gas demand from
distribution networks (concentrated in the commercial and residential
sectors) by over 30% year-on-year and effectively delayed the start of the
heating season in most European markets. This steep decline in demand
coincided with a persistently strong influx of LNG cargoes, which have
limited immediate flexibility to change destination, as deliveries are
typically scheduled several weeks in advance.
Lower-than-expected demand, together with high LNG inflow and healthy
storage levels, pushed down European gas prices. Month-ahead prices on
TTF fell to just below EUR 100/MWh (USD 30/MMBtu) by the end of
October. This was less than one-third of the all-time high at the end of
August but still more than five times the 5-year average during the 2016-20
period. Day-ahead prices – which are more reflective of short-term supply-
demand factors – fell below USD 10/MMBtu at the end of October, while
next-hour prices dropped into negative territory for a short period on 24
October amid infrastructure constraints in the TTF market zone.
The temporary comfort provided by today’s
market conditions should not lead to overly
optimistic conclusions about the future: a cold
spell could quickly change sentiment and
Europe’s gas balance faces even tougher tests in
2023
While EU gas inventories are standing 5%, or 5 bcm, above their 5-year
average, this additional storage cushion could be quickly erased: 5 bcm is
just two days of EU gas demand during a cold spell.
There is a wide range of possible outcomes for EU gas storage at the end of
this winter heating season. Assuming no or very low Russian gas deliveries
to the European Union this winter, and average levels of LNG imports
(around 13 bcm per month), then gas storage levels could be anywhere
between 5% and 35% by the end of the heating season, depending on
demand trajectories over the coming months.
Variable demand trajectories, which can be influenced by policies as well as
prices and weather, translate into a variety of future scenarios for gas
injection needs during the summer of 2023. These vary between 60 bcm
and 90 bcm in order to reach 95% storage levels by the beginning of the
2023-2024 heating season.
Considering current market trends, our assessment today is that the storage
injection needs of the European Union and the United Kingdom will be 68
bcm (including 1.68 bcm of injections to the Rough storage in the United
Kingdom). This is based on the assumption that European gas demand
during this November-March period is 11% below its 5-year average. A
colder-than-average winter could deplete European storage levels faster,
resulting in injection needs in the range of 80-90 bcm.
Measures to limit short-term demand and storage depletion, alongside more
structural measures to bring down gas demand, are absolutely essential to
position Europe for next year. The drive to refill Europe’s gas storages for
the 2023-24 winter heating season has to begin now.
Some of the factors that helped Europe in 2022
are unlikely to be as favourable in 2023: in
particular, Russian deliveries are likely to be
considerably lower and competition from China
for available LNG cargoes considerably higher
Although Russian gas deliveries to Europe were cut sharply during 2022,
they were close to ‘normal’ levels for much of the first half of the year.
Total pipeline supply from Russia in 2022 is likely to amount to around 60
bcm. It is highly unlikely that Russia will deliver another 60 bcm of piped
gas in 2023. If supply remains at current levels, then Russian pipeline
supply would be around 25 bcm in 2023. It is also entirely possible that
Russian deliveries could fall further – or cease entirely.
Non-Russian pipeline suppliers have limited upside potential, with both
Azerbaijan and Norway supplying close to their nameplate capacity in
2022. In the case of Algeria, some limited upside is expected with the
development of gas fields in the Berkine South basin.
Global LNG supply is expected to increase by 20 bcm in 2023, supported
mainly by the ramp-up of the Calcasieu Pass LNG facility in the United
States and the Coral South LNG facility in Mozambique, as well as the
return of the Freeport LNG facility in the United States. However, this
increased LNG supply will not be not sufficient to offset the likely decline
in Russia’s pipeline deliveries to the European Union.
Domestic gas production in the European Union is set to decline in 2023. In
the Netherlands, production at the Groningen field was capped at 2.8 bcm
for the 2022-23 Gas Year1, down from 4.5 bcm in the 2021-22 Gas Year.
Production from small fields in the Netherlands also continues to decline. In
Denmark, the restart of the Tyra field was postponed to the 2023-24 winter
–meaning that it will not contribute to the refilling of gas storages during
summer 2023. In the United Kingdom, gas production recovered strongly in
2022 and the potential for further short-term growth is limited.
Even more significantly, China’s LNG imports could rebound next year.
China’s lower LNG imports in the first ten months of 2022 were a key
enabler of higher LNG availability to Europe. A return to stronger Chinese
economic growth and some easing of lockdowns could bring 2023 LNG
imports back to their 2021 levels (108 bcm), which would capture over 85%
of next year’s expected increase in global LNG supply and limit the amount
of LNG available to the European market.
China has pursued a strong LNG contracting strategy in recent years. As a
result, China’s reliance on destination-fixed LNG contracts is set to increase
from 88 bcm per year in 2022 to 100 bcm per year in 2023. This effectively
means that China will have the right-of-first-refusal on an additional 12
bcm of LNG – well over half of the expected increase in global LNG
supply in 2023.
In mid-October, it was widely reported that China’s National Development
and Reform Commission had asked state-owned gas importers to stop
reselling LNG to buyers in Europe and Asia to ensure stable gas supply
ahead of winter.
EU gas exports to Ukraine are set to rise. Ukraine started the 2022-2023
heating season with storage levels at just 14 bcm – well below their historic
average. Even assuming a 25% reduction in the country’s winter gas
consumption, storage sites are expected to be severely depleted by the end
of March 2023. Our analysis indicates that Ukraine would require at least 5
bcm of gas imports from the European Union during the summer of 2023 to
replenish its storage levels to 14 bcm by the start of the 2023-2024 heating
season.
Europe could face a 30 bcm shortfall in the gas it
needs to fuel its economy and sufficiently refill
storage sites during the summer of 2023,
jeopardising its preparations for the winter of
2023-2024
A full cessation of Russian pipeline gas supplies to the European Union
combined with a return of Chinese LNG imports to their 2021 levels would
lead to a shortfall of 30 bcm of gas in Europe during the summer of 2023,
the period when gas storage sites need to be refilled.
This equates to almost half of the injections required to fill storage sites to
95% of capacity by the start of the 2023-24 heating season. This is based on
the assumption that natural gas demand in the European Union and the
United Kingdom will decline by 11% compared to its 5-year average during
the November 2022 – March 2023 period and that Europe’s gas storage
sites will be around 30% full at the end of this winter.
A recovery in European hydropower generation to its 5-year average and
higher nuclear power output in France (aligned with the mid-range of
EDF’s latest guidance) could reduce the shortfall to 22 bcm, but it would
not eliminate it.
This puts the spotlight back on natural gas demand. Shortfalls in available
supply would put immense pressure on prices again, but this could be
relieved by accelerated structural changes in European gas demand.
An even faster deployment of renewables, heat
pumps and energy efficiency measures can
mitigate the risks of a worsening energy and gas
crisis
While healthy storage levels and unseasonably mild weather at the
beginning of the 2022-2023 winter season provide some temporary relief to
gas and related energy markets in Europe, our analysis indicates that
supply-demand fundamentals are set to tighten in 2023.
A more rapid deployment of renewables, heat pumps and energy efficiency
measures can mitigate the risk of a worsening energy and gas crisis.
However, this would require immediate action from governments.
The IEA will present a roadmap for securing Europe's gas balance for next
winter showing what is needed to ensure storage sites are filled to 95%
capacity by the beginning of the 2023-2024 heating season and to
structurally reduce gas consumption during the winter. Key measures
include:
Speeding up investments in energy efficiency improvements.
Faster deployment of renewables.
Accelerated installation of heat pumps.
Identifying remaining fuel-switching options in industry and the power
sector.
Behavioural changes.
A further push to accelerate structural changes and reduce gas consumption
is essential not only for Europe’s clean energy transitions but also for its
energy security and the wellbeing of its citizens and industries.
The current market context requires greater attention to instruments and
measures that could facilitate investment in methane abatement options.
Republished from IEA under CC BY 4.0 licence
2. The 5th EU electricity market reform:
a renewable jackpot for all Europeans
package?
Electricity prices are extremely high. We are short of gas in Europe, and gas
power plants are pushing up the prices of electricity. It is also unfortunate
that an unprecedented number of nuclear power plants are under forced
maintenance in France, which increases electricity prices even further.
Consumers are suffering, and some producers of electricity are making
unexpected profits.
Many emergency measures have been taken to protect consumers and to
claw back windfall profits. Beyond these short-term measures, the process
towards an electricity market reform for the medium to long term has also
started. This could become the fifth EU electricity market reform.[1]
In the ongoing debate, some have argued that electricity markets are broken
and that we should suspend or radically change them.[2] The objectives of
this revolution are to decouple gas and electricity prices, eliminate windfall
profits, and give consumers access to cheap renewables. Many
revolutionary proposals have been made, like splitting the market into
groups of technologies according to their characteristics and to price or
regulate them separately. With these proposals, we risk going backwards in
the European electricity market integration process by introducing new
obstacles for cross-border trade. This would be unfortunate because the
market integration benefits are increasing with the ongoing transition to
renewables.
The good news is that going backwards is not necessary. The Renewable
jackpot for all Europeans can be organised with the electricity markets we
have jointly developed over the past two decades.[3] We ‘only’ have to
complete these markets, and we have to combine them with a few
instruments that have already proven their usefulness during the current
crisis. These instruments could be at the centre of the market reform. It
could become a revolutionary reform, but one that goes forward instead of
backwards.
To illustrate this point, I will discuss electricity markets and the following
instruments: Contracts for Difference (CfD), Power Purchase Agreements
(PPA), Capacity Remuneration Mechanisms (CRM), Energy Communities,
and Demand-side Flexibility. The discussion is organised in three steps: 1/
introduction; 2/ performance during the crisis; 3/ lessons learned for the
reform. I do not claim that this is an exhaustive scope for possible reform,
but it is at least a start.
Note, to conclude this introduction, that the fourth electricity market reform
took several years to develop with studies, impact assessments and public
consultations. The European Commission’s work plan foresees a reform
proposal in 2023, which would be much faster than usual, and the European
Council in October 2022 asked the Commission to speed up even more.[4]
Speed is important, the crisis requires us to move, but are we not confusing
reforms with emergency measures?
Electricity Markets
Introduction. In Europe, we have a sequence of electricity markets from
forward to day-ahead, intra-day, and balancing markets. These markets
allow us to exchange electricity across country borders with standardised
contracts from a few years ahead of delivery all the way to real-time. We
have discovered that this is very beneficial because we are saving billions
of euros every year.[5] This achievement is unique in the world, and it is an
important asset in the transition towards a more sustainable energy system.
Performance during a crisis. When market integration started, Belgians
feared transits would increase between France (exporter of nuclear power)
and the Netherlands (importer of power) with limited benefits for Belgium.
A few years later, Belgium faced power shortages in winter, and the country
was saved by imports. Today France is short of power, so the market is
helping to save France. Electricity markets in Europe are a stabilising factor
in times of crisis, and also organise solidarity among countries. If we were
to suspend electricity markets, it would be up to governments to organise
that solidarity. We risk short-sighted and expensive blame games with
limited solidarity. In the current debate, the market is seen as the problem,
but the problem would be much worse if it were not for energy markets that
organise the flow of energy to where it is most needed. Sharing our
resources across borders via markets (and cross-border network
infrastructure) will be even more important in a future with renewable
energy. The alternative is that each country invests in their own backup
systems and flexibility, which would be way too expensive, and also
unnecessary as long as we do not close our borders within Europe.
Lessons learned for reform. The crisis has been a wake-up call for the
importance of hedging and the regulatory framework for long-term
investments. We all wished we had entered into a fixed-price retail contract
or another insurance against high prices, and some retailers have gone bust
during the crisis because they were not sufficiently hedged. Academics
have long talked about completing the EU electricity markets with better
functioning forward markets. There are many ideas to do that, like
introducing regulated incentives for consumers and retailers to hedge, or
coupling forward markets across borders. Each of these ideas deserves to be
looked at in more detail.
Contracts for Difference (CfD) and Power
Purchase Agreements (PPA)
Introduction. As renewable energy has matured, subsidy schemes have
also evolved. We gradually integrated renewables into electricity markets.
Many countries started with fixed ‘feed-in’ tariffs and no exposure to
market prices for renewable developers and then evolved towards
‘premium’ schemes with the support that comes on top of market prices.
More recently, countries started to introduce Contracts for Difference
(CfDs) to support renewable energy. The developers compete via tenders
for the price they need to cover their investment costs. If market prices turn
out to be lower than the awarded price, governments cover the difference; if
market prices are higher, developers pay back the difference. These
contracts have to be two-sided (or symmetric), and they can also be
tweaked to make them compatible with short-term markets, to preserve the
incentives for the developers to respond to prices, while still capping their
revenues.
Performance during the crisis. Renewables have been blamed for making
windfall profits during this crisis. Retroactively taxing them or capping
their revenues is difficult and creates a lot of distortions. Meanwhile,
government entities that entered into CfDs with renewable developers have
already experienced a renewable jackpot, which is for example the case in
Denmark, France and the UK. When entering into these contracts,
governments probably did not anticipate earning so much money. In the
current crisis, the public money that governments hand out to compensate
for high prices is much larger than the money they collected with CfDs, but
this could change in the future if these contracts become the standard, and if
we improve our consumer support schemes.
Lessons learned for reform. The more we invest in renewables, the more
we decouple the price of electricity from the price of gas. If we want to
guarantee that consumers have access to cheap renewables, governments
could further develop CfDs on their behalf. We then need to think about
how the money that these contracts raise during a crisis can be used to
support consumers in periods of high prices. The support should target
those most in need, and it is also important that we preserve the incentive to
save energy during a crisis.[6] Another option would be to have an entity
mandated by member states to act as an intermediary so that consumers can
buy these contracts as insurance against high prices. Note that some large
consumers and suppliers already entered into Power Purchase Agreements
(PPA) with renewable developers, but these agreements can be indexed to
spot prices, which does not help in times of crisis (and in retrospect also
does not benefit developers who now face measures against their windfall
profits).
Capacity Remuneration Mechanisms (CRM)
Introduction. Utilities have long argued that electricity markets need to be
supplemented with capacity remuneration mechanisms to make sure that
there are adequate investments. Even if we complete our shorter-term
electricity markets with better-functioning forward markets, these markets
do not necessarily guarantee that we have enough investments. However,
before the crisis, the common concern was that these mechanisms would be
abused to favour certain technologies, or to provide state aid to utilities that
are not able to recover the investment costs of outdated and dirty
technologies.
Performance during the crisis. The costs of being short of energy are so
high, that I think we are all willing to pay a bit more to avoid another
supply shortage with extreme prices. As we expect demand to go up due to
the electrification of transport, heating and industry, we seem to be more
worried about under-investments than over-investments. If we use CfDs to
accelerate the investments in renewables, we can use capacity remuneration
mechanisms to ensure that we have enough investments in backup power
and flexibility, which can be a combination of low-carbon dispatchable
generation, energy storage solutions and demand response.
Lessons learned for reform. The EU Clean Energy Package paradigm was
to avoid the abuse of capacity mechanisms. The package also made sure
that these mechanisms are designed in a way that minimises the possible
negative impact on short-term electricity market signals. If we change the
paradigm and consider these mechanisms part of the electricity market
target model, we can go a step further in harmonising and integrating them.
This could be achieved through network codes and guidelines, which is a
process that has also been successfully used for other aspects of electricity
markets.
Energy Communities
Introduction. The EU Clean Energy Package introduced a regulatory
framework for individual and collective action by citizens to take
ownership of the energy transition. Energy cooperatives have been around
for a while. Several of them were initiated by activists that wanted a greener
and more local supply of energy, and took matters into their own hands.
Their purpose is primarily driven towards social and environmental benefits
rather than financial profitability. Members of such communities are often
willing to pay a premium for greener energy.
Performance during the crisis. Most energy communities co-invest in
renewable energy, some also source their energy with long-term power
purchase agreements from local renewable energy producers. This business
model was not designed to be a hedge against extreme prices during a
crisis, but it turned out to be cheaper than market prices in recent times. Co-
investing in renewables is also cheaper and more efficient than doing it
alone. Of course, the hedge against market prices is not perfect,
communities still have to source some of their energy from the market, but
it can contribute to protecting consumers from high market prices. Energy
communities can help consumers to take ownership of the transition.
Lessons learned for reform. If more citizens want to join a community,
and if we want to make sure that they have access to renewable projects, we
need to strengthen the regulatory framework for renewable production,
energy sharing and supply. Some countries have enabled communities’
participation in tenders for large renewable energy projects; maybe they
could also be given access to CfDs and receive a role in public-private
partnerships. Local authorities could give energy communities access to
public buildings to invest in PV panels, and they could make sure that
vulnerable consumers are integrated in these communities. Energy
communities can be involved in social housing projects, and many other
best practices that are emerging across Europe. To upscale these initiatives,
further technical assistance, capacity building and awareness-raising
activities for communities and citizens should be developed.
Demand-side Flexibility
Introduction. The EU Clean Energy Package represented a big step
forward to engaging consumers and modernising networks and system
operations. Consumers are for instance entitled to a smart meter in
combination with a dynamic retail price contract. TSOs are increasingly
welcoming aggregated flexibility in balancing markets. DSOs are
increasingly engaging with flexibility service providers at the local level to
manage congestion in their grids.
Performance during the crisis. For the moment, extreme prices have
solved our shortages. In countries that did not cap retail prices, domestic
and industrial consumers did respond by saving energy, we only wished that
demand would be more flexible and respond at lower prices. However, we
are also reminded that we are not yet well-organised to deal with
emergencies. If everything is voluntary, and people are not responding
enough to the price signals, we would need to ration energy. We have load-
shedding plans to organise rationing in case of emergencies. We always
hope that we will never need to implement these plans. For instance, in the
winter of 2021, Texas did have to activate their load shedding plans, which
led to a lot of chaos and public outrage. People did not understand why they
were cut off from the electricity system, while others could continue to
consume unlimited volumes. The rotation of the power cuts was unclear,
and some grid users also discovered they were never cut because they
happened to be connected via the same feeder of a hospital or another
protected consumer.
Lessons learned for the reform. The EU Clean Energy Package’s
paradigm was to focus on voluntary flexibility, which is incentivised via
cost-reflective network tariffs, dynamic retail prices and market-based
procurement of flexibility services by the system operators. For emergency
situations, it would be useful to get a step further. We should be able to
reduce everyone to basic energy consumption, which would be less painful
and more acceptable than rotating power cuts. Grid users could also
volunteer to be cut in case of emergencies in exchange for compensation.
We could ask all retailers to offer subscriptions with different levels of
guaranteed supply. Hedging can then be about volume as well as price. We
could ask all TSOs and DSOs to offer firm and non-firm connection
agreements, or different levels of discounted non-firm connection
agreements. It would imply that we evolve from voluntary flexibility
towards a combination of voluntary and smart mandatory (backup)
schemes. This will be necessary to deal with (temporary) bottlenecks in
electricity networks, and could also save us from chaotic rolling blackouts
in case of emergencies.
By Leonardo Meeus
Republished with permission from Florence School of Regulation
3. What can China’s electricity markets
draw from international experience?
The electricity market is set to play a key role in China's construction of a
new energy based power system. Although China has made substantial
initial progress, its electricity market still faces an uphill struggle in
promoting the consumption of renewables, resource allocation across
provinces and regions, and unlocking demand side potential. What can the
world’s mature electricity markets show China? Daisy Chi offers some
insights from the Handbook on Electricity Markets, as well as part of the
discussion at an event launching a Digest of the Handbook in November
2022.
Power market reform in China: achievements so
far
Over the past two decades, China has been steadily developing its own
unique power market system. The journey started with a massive
reorganisation of the electricity sector in 2002, when power generation and
the grid sector were unbundled. A new round of power system reform in
2015 heralded an acceleration in China’s power market development: the
sector moved away from an administrative allocation system and towards a
market-based system, characterised by mid- and long-term contracts
between electricity producer and consumers, and the emergence of
competitive retailers. Wholesale and spot power market structures have
been taking shape since then. More recently, with the power tariff reform in
October 2021 that allows for market-formed and more fluctuation in power
prices, and the announcement of a new national power market system in
January 2022, China’s power market development has moved into a whole
new phase.
Although the Chinese power market is still in its infancy, some noticeable
progress have been achieved so far. The country is increasingly
emphasising market-based means to build towards a renewable-based new
power system. The mid- and long-term power market, which covers a large
percentage of total demand in individual provinces, has been gradually
expanding. Additionally, spot market pilots have got under way. There are
new requirements for all coal-fired generation as well as industrial and
commercial power users to participate in power market trading. All these
reforms are helping to unlock a booming electricity market. As a result,
China is seeing rapidly expanding power transaction sales and a growing
number of market participants. According to the statistics of China
Electricity Council (CEC)[7], a total of 3,700TWh of electricity was traded
in the country’s power markets in 2021, nearly five times higher than in
2015, and accounting for 44.6% of the overall electricity consumption. By
the end of 2021, 467,000 registered entities were taking part in various
power trading centres across the nation, up 76% in just one year[8].
Obstacles and new challenges
Although these numbers seem encouraging, there is a long way to go before
China will be able to boast of a unified national electricity market system.
As noted by Yang Kun, President of China Electricity Council, the power
market rules in the country’s regions have yet to be aligned by reforming
policies and market mechanisms. In addition, the green value of renewable
power is not fully reflected in the current power market, and this is
hindering market participation. Meanwhile, the connections between the
electricity market and the green certificate trading / the carbon market,
between the mid- and long-term wholesale market and the spot market, and
between the inter- and intra-provincial power market, all need to be
strengthened[9].
China’s power market reform is an essential part of the country’s efforts to
achieve its carbon peaking and carbon neutrality targets. This national
strategy, which requires decarbonisation within just 30 years, is posing
unprecedented challenges to the existing power system, which is built
primarily on fossil fuels.
In the context of constructing a new power system, the growing proportion
of variable and intermittent renewable energy in the system is making it
more difficult to balance supply and demand, given the vulnerability of
these energy resources to weather conditions. Market mechanisms are
crucial if the flexibility potential in the system is to be unlocked.
At the same time, the rapid development of renewable energy is set to add
significantly to the overall system costs, given the associated need for
storage and flexibility resources as well as power network expansion and
reinforcement, warns Ma Li, Vice Chief Engineer of State Grid Energy
Research Institute. It is crucial for the power market design to take account
of the higher operational costs by introducing an appropriate price
mechanism on both supply and demand sides to guarantee a fair return on
investment for all parties.
An even more complex challenge is looming: how to encourage renewable
energy companies to participate in the power market. Recent research
conducted by CEC found that on average only 30% of renewable energy
companies are participating in power market trading. The only regions to
exceed that percentage tend to be in the central and western regions of
China[10]. The settlement price of renewable power in the spot market is
generally lower than its fossil fuel equivalent and does not fully reflect the
green attributes of renewables, and this price discrepancy is hampering
market participation. The current market arrangements were originally
designed for conventional power supplies, and are not appropriate for the
output characteristics of renewables. The result is a lack of competitiveness
when renewables join the spot power market. All of these challenges
inevitably require systemic adjustment in policy support and a complete
transformation of existing market mechanisms.
Handbook on Electricity Markets: a classic
reference tool
Given that China is still developing its national electricity market, this is a
good time for its specialists to observe and draw on international
experiences and deepen their understanding of the various market
mechanisms in the global energy market in order to better design a market
that takes into account the particular characteristics of the situation in
China. The publication of the Handbook on Electricity Markets in
November 2021 could not have come at a better moment. Edited by Jean-
Michel Glachant, Director of the Florence School of Regulation, Paul L.
Joskow, Massachusetts Institute of Technology, and Michael G. Pollitt,
University of Cambridge, the 600+ page Handbook brings together insights
from some of the most brilliant thinkers and experts in the field of
electricity markets.
The book is composed of two sections with 22 chapters. The first section
offers an overview of the current legacy state of power markets around the
world. It not only covers the fundamental theories of traditional
arrangements for electricity supply, wholesale and retail electricity markets
and price design, but also provides detailed analysis and key lessons learned
in major electricity markets in Europe, the UK, Australia and the USA. The
second section focuses on the future, discussing how the electricity market
is evolving to adapt to the current new situations that are being shaped by
higher renewable penetration and new market drivers, such as the
emergence of new technologies on the supply and demand side, tools and
policy priorities for decarbonising power systems, future electricity market
design, new characteristics in balancing supply and demand, as well as
emerging business models.
EU-China Energy Cooperation Platform (ECECP) has commissioned a
Digest of the Handbook with funding from the EU. Co-authored by Jean-
Michel Glachant and Nicolò Rossetto, the Digest presents the Handbook’s
wealth of information in a highly condensed form in both English and
Chinese, so that the key points are more available to busy decision-makers.
What’s more, the edition of the Digest available for distribution in China
features an extra chapter ‘Takeaways from the Handbook on Electricity
Markets in China,’ written by Michael G. Pollitt, which draws key insights
from each chapter and highlights how they relate to the issues and
challenges faced by China. A complete Chinese translation of the
Handbook is also under preparation by ECECP. Publication will be in 2023,
offering a more detailed reference for Chinese readers.
Some key insights for China
Will this Handbook help to solve some of the profound puzzles for China in
optimising its own power market? According to Mrs Ma Li, the Handbook
is informative and very valuable to Chinese electricity market researchers
and practitioners, particularly in view of its in-depth analysis of mature
market models across the world. Many key issues currently encountered in
China’s electricity market, including provincial and regional market
connections, market mechanisms that allow for variable renewables and
encourage their consumption, as well as strategies to unlock the demand
side flexibility potential, are addressed in detail in the Handbook.
● Market models to achieve a unified national market
In China, there is an unbalanced geographic distribution of renewable
energy supply and demand as well as curtailment issues in the renewable
rich regions. This means that green power output need to be allocated and
distributed on a wider scale, which is exactly the point of building a
national power market.
There has been a wide-ranging discussion about which mature power
market model China should adopt in order to build a fully functioning
national market by 2030. The US PJM model, as well as the standard
market design of the European system, both covering large geographic
areas of different states, are two typical and often cited models that have
particular relevance for China[11]. However, as Dr Michael G. Pollitt argued
at the launch event of the Digest, the PJM market, famously including a
day-ahead spot market and nodal prices, might not be the ideal option for
China: its efficacy depends on the particular conditions of the US market,
such as the difficulty in expanding the transmission system, which does not
seem to be a pressing issue in China. In addition, to expose everybody to
time and space varying prices could be even more problematic in the
Chinese context at present.
The European single market, on the other hand, represents a textbook
example of the long-running integration of different sub-regional and
national markets. This bears similarities to China’s current efforts to bring
the Chinese provincial system into a single market. According to Dr Pollitt,
the European single market case makes it clear that there is a substantial
role for the European Commission and a need for very significant
interventions to reduce gaming in inter-jurisdictional trading and so to
reduce the power of incumbent companies and their national regulators. ‘A
key lesson for China is that strong regulatory leadership from central
government is needed in supporting the provinces in order to develop a
genuine national market, and that simply concentrating on developing
markets at provincial level may miss a huge benefit,’ noted Pollitt.
● Market mechanisms to accommodate high-share of
renewables
Even as China moves towards a new power system, the rise of intermittent
renewables poses on-going challenges to system security, because the
availability of renewables does not necessarily correlate with demand.
‘Whenever we’re thinking about matching supply and demand in the power
market, we can either do it through price mechanisms or we can do it
through some sort of quantity control. So, if we have a shortage of
electricity generation from renewables, we can ration electricity demand
through some sort of rationing algorithm which people have agreed to in
advance. This offers an alternative to simply exposing people with higher
prices in real time market,’ notes Pollitt. In terms of future electricity
market design[12], Pollitt stresses that long-term contracting coupled with
short-time quantity control will allow China to cater for the characteristics
of a new power system based on renewables, as this long-term model
emphasises flexible qualities rather than flexible price.
All around the world, many mechanisms have been explored that offer
reliable operation of a power system that can incorporate a growing share of
renewables, such as new auxiliary service mechanisms to encourage
flexibility, capacity compensation for power sources that supporting system
reliability, establishment of a capacity market to supplement energy markets
and to ensure resource adequacy, as well as scarcity pricing mechanisms.
All of these mechanisms, discussed in detail in the Handbook with actual
examples and lessons learned, are worth further exploration in the Chinese
context.
In addition to the need to secure system reliability, there is another factor:
decarbonisation. The design of the market mechamism should reflect the
green value of renewable energies. This is vital to encourage renewable
energy producers to participate in the market. There are many existing
market-based tools such as green certificates, green power trading and the
carbon market, which complement each other and all work towards the
same goal of promoting the participation and consumption of renewables.
Although building blocks are in place for China, such as the newly
established national carbon market, Pollitt suggests that such tools need to
become more integrated, and that renewable subsidy schemes need to be
developed alongside. ‘More importantly, prices and ambition need to rise to
a certain high level where it’s actually making a difference in the power
sector,’ said Pollitt.
● Unlocking the potential of demand side flexibility
Unlocking the potential of the demand side is key to being able to manage
intermittency, and constitutes one of the main reasons for development of
an electricity market, said Pollitt in the launch event. It is not only about
accelerating the development of various demand side technologies, such as
energy storage and EVs, but also about who should manage them, and in
what way. As most end users are not currently able to participate directly in
the power market, the question of how they should be included in the power
market – initially through retailers or suppliers - is absolutely crucial.
China’s introduction of large numbers of competitive electricity retailers
since 2015 shows that it recognises the importance of the demand side,
notes Pollitt. However, he remarks on an apparent lack of understanding
about the potential role for competitive retailers: a truly competitive retail
market is yet to be established.
‘Full retail competition is about competition in who bundles wholesale
contracts, meters, invoices and manages the customer relationship.
Successful retailers should have been innovative with respect to the
customer relationship and have experimented with different degrees of
integration with generation. However, China is not moving towards this sort
of retail competition.’ writes Pollitt in the Digest. He further stresses that ‘a
key argument for China is that without wholesale market pricing and retail
competition, the potential on the demand side in China cannot be fully
unlocked.’
Looking into the future, the transformation of passive consumers into active
market participants enabled by new demand-side technologies offers
enormous potential for system flexibility, which could be unlocked by new
business models that offer new options for reactions to market signals and
grid incentives[13]. Pollitt suggests that more experimentation is needed in
China to find out what payment regimes will encourage power users to be
more flexible and elicit the biggest demand response, whilst also being
politically acceptable. In this context, it is worth studying some of the
experiments that have already been trialed in other parts of the world with
respect to consumer behaviour.
More to be explored
In conclusion, there is a great deal of relevant information for a Chinese
audience in the 600+ pages of the Handbook. ECECP is hoping anticipates
that the Digest will help China to avoid some of the pitfalls encountered in
other countries, and that market players will choose to take the opportunity
to find out about some of the successful – and not so successful – market
developments throughout the world.
The condensed version - Digest of the Handbook on Electricity Market - is
now available with open access on the websites of both ECECP and FSR.
Click the underlined links to download.
By Daisy Chi
4. China’s power system needs to
modernise
Cheap hydrogen produced from industrial by-products may help the
hydrogen sector develop, but there is a risk of locking in carbon emissions.
The Baihetan hydropower station, which straddles the provinces of Yunnan and Sichuan in southwest
China
(Image: Cao Mengyao / Alamy)
Sichuan, the most densely populated and industrialised province in south-
west China, relies heavily on hydropower. This summer it was hit by
extreme heatwaves and drought, causing reservoirs to dry up and the power
system to suffer.
To keep power flowing to homes, the local government pulled the plug on
factories for two weeks. But as the drought dragged on, household supplies
were affected too.
Experts say the crisis highlights thorny and longstanding problems for
China’s electricity reforms: inflexible markets, insufficient demand-side
response, and a failure to tune and balance the power system. Together,
these mean a drought can quickly cause electricity shortages. And the
growing threat of climate change impacts may be more than the ageing
system can handle.
China must decide: should it shore up the existing system with more coal
and gas power or speed up its reforms?
Crisis
Sichuan is known as the province of a thousand rivers, counting 1,419 of
them, large and small, within its borders. It also boasts diverse terrain,
stretching from the heights of the Qinghai-Tibetan Plateau and the
Hengduan Mountains down to the Sichuan Basin, with a fall of almost
7,000 metres between its highest and lowest points. That makes Sichuan
ideally suited for hydropower, which now accounts for the lion’s share of its
energy mix.
Hydropower accounted for 77.39% of the province’s total generating
capacity of 114 gigawatts (GW) in late 2021.
In normal years, summer is the rainy season. Rivers rush east off the plateau
and are channelled through turbines as they go, generating huge quantities
of electricity. This isn’t just for Sichuan’s own needs. There is a surplus for
export to Shanghai, Zhejiang and the other industrialised provinces in
eastern China.
A small hydropower station on the Zhou River, Dazhou City, Sichuan, which has stopped working due
to lack of flow, August 2022 (Image: Tom Wang / Alamy)
But climate change transformed this year’s rainy season into a drought, with
rivers in the Yangtze Basin running dry when least expected.
In July and August, rainfall in the Sichuan Basin was half or more below
usual levels. Meanwhile, temperatures were 2.3C higher than average
between June and the end of August, the highest since full records started in
1961, according to the Sichuan Climate Centre.
Those historic highs meant new lows for hydropower generation.
According to the Sichuan Daily, by 16 August, water in a number of
important reservoirs had reached the ‘dead level’, meaning there was no
longer enough to run the turbines. Hydropower generation was 50% lower
than in the same period the previous year. Meanwhile, the hot weather had
locals reaching for their air conditioning: the demand for electricity
province-wide shot up 25% year-on-year.
The electricity system was overdrawn and at risk of collapse. If the load
stays too high for too long, the grid can fail and cause widespread
blackouts. Sichuan had no choice but to pull the plug on its factories. That
continued until the end of August, when cooler air blew in from the north,
pushing out the subtropical high pressure. Rain fell at last and the crisis
drew to an end.
Coal power raises its head again
Some said the crisis could be blamed on an over-reliance on hydropower
and that more thermal power plants were needed to ensure stable supplies.
Sure enough, after the shortages, the provincial government put policy
incentives in place for new gas-fired power plants. In October, it issued a
document saying it would make capacity payments to gas-fired plants that
can regulate power at peak times, the first such statement in China. That
would mean payments could be collected by a power plant even when it is
on standby.
Since mid-July, Caixin reports that provinces including Guangdong, Anhui,
Xinjiang and Guizhou have put building new coal power plants on their
agenda. Total generating capacity when built, according to Caixin, would
come to almost 17 GW. It looks like China may see a wave of coal power
construction in the coming three years.
That trend can be traced back to September last year when several
provinces were hit by electricity shortages. In the final quarter, approvals
for coal power plants suddenly increased compared to the same period in
2020. Almost 20 GW of coal power plant construction was approved in the
six months from October 2021 to March 2022, according to a Greenpeace
briefing, which judged that the need to ensure supplies and energy security
was now driving the electricity sector.
Yuan Jiahai, a professor at North China Electric Power University’s School
of Economics and Management, told China Dialogue: ‘We have seen a lot
of electricity supply issues these two years. What to do? If we build more
coal power then it’ll be there when we need it, but utilisation rates will
usually be very low. It’d be an ongoing waste in order to ensure we don’t
see shortages in a crisis. For policymakers, security and stability come
first.’
Yet, more coal power won’t necessarily make the system more secure. An
unexpected jump in coal prices could also trigger a crisis.
That was what caused last year’s shortages: a disconnect between coal
prices and power prices meant many coal power plants were losing money
with every single kilowatt-hour of power they produced, so they shut down.
Moreover, coal power is no less vulnerable to extreme weather than
hydropower. In July 2021, a downpour in Zhengzhou left the local
electricity system reeling. A Yuneng Power plant to the west of the city
flooded and was at risk of being unable to continue generating. The same
downpour damaged the electricity infrastructure in Zhengzhou, Luoyang,
Jiaozuo and elsewhere.
Any single piece of infrastructure can fall foul of unpredictable risks: a dry
summer, a sudden downpour, or high coal prices. The question is, how do
we ensure the system as a whole can stay safe and stable?
An inflexible system
Electricity systems have three connected stages: generation, transmission
and distribution. This year’s problems in Sichuan were mainly caused by a
large and sudden drop in generation. A simple solution would be to add
more generating capacity to cover any fall. But the underlying problem is
more complex.
Sichuan is China’s biggest exporter of hydropower, with one-third of its
generation sent to places like Jiangsu, Zhejiang and Shanghai in the east,
rather than meeting local demand. If it hadn’t been for those existing
commitments, Sichuan could have kept the factory lights on.
Of the province’s 114 GW total generating capacity, 88.87 GW is
hydropower, 18.25 GW is thermal power, and 7.23 GW is new energy. Even
operating at half of the total capacity, Sichuan’s hydropower plants can
generate 40 GW.
Yuan Jiahai and others have calculated that with thermal power running at
full capacity, as well as 3 GW of generation from new energy sources and 4
GW in electricity imports from elsewhere, Sichuan had a total of 65 GW of
power. That is equal to the province’s peak demand, meaning balance could
have been maintained.
However, cross-provincial electricity transfer agreaements (both under
government instruction and as deals between grid operators) mean that a
significant part of Sichuan’s generated power is sent east. At the worst point
of the drought, only 23–25 GW of hydropower was available for local use,
leaving a peak-time shortage of around 15 GW.
The Baihetan to Jiangsu ultra high voltage transmission line is a key part of China’s ‘west–east
power transmission’ strategy (Image: Alamy)
As well as the cross-provincial agreements, this situation is also due to the
physical design of the grid and how the system works.
‘The cross-regional energy market is planned at the national level and
designed and operated based on direct current, high volume and
unidirectional transmission of power,’ said Yuan Jiahai.
He added: ‘Such a grid design does not allow Sichuan to keep more power
for itself. And the system as it stands doesn’t give Sichuan the authority to
change planned transfers. When the crisis started, Sichuan declared a ‘Class
I power supply emergency’ after approval from national energy supply and
security authorities. Only after allocation of supply and demand at the
national level was Sichuan able to keep more power for itself.’
Indeed, in China, investment and cross-provincial electricity dispatch is
planned at the national level, with provincial authorities mainly in charge of
implementing those plans, according to a 2019 report by the China Electric
Power Planning and Engineering Institute. When things go off the rails,
existing systems do not allow those in immediate control to respond
quickly.
‘It’s inflexible and lacks market mechanisms,’ said Yuan Jiahai. ‘Long-term
cross-provincial deals and trading schemes determined at the national level
are set in stone, so there’s very little scope to make use of cross-provincial
spot markets to improve the situation at the margin.’
Away from the supply side
In 2015, the State Council published a document on further reforms to the
electricity system known as Document No. 9. It referred to a lack of market
mechanisms and problems coordinating national- and provincial-level
planning.
Yuan Jiahai said electricity trading should ‘send electricity wherever
demand is highest’, similar to the bilateral and bidirectional agreements
common in Europe but entirely absent in China. ‘In other words, our
regional markets are lagging far behind.’
‘The situation this summer showed how much room there is for more
coordination in the existing system,’ he said. If there were a regional
market, he added, higher prices could have been used to encourage other
provinces to fire up reserve capacity and allow Sichuan to retain more of its
own electricity. That would have eased problems for the province and been
much less damaging than the factory shutdowns. But the costs of doing this
would need to be spread fairly. Under market mechanisms, Sichuan would
have to be willing to pay more for power originally destined for export,
prompting eastern provinces to use reserve generating capacity to meet their
own needs.
‘I think there’s a lesson here for government and market actors: electricity
security and guarantees come at a cost, and low prices can’t necessarily be
maintained under all circumstances.’ But, he warned, the reforms cannot
happen overnight. There will need to be a managed process.
Another problem is that the demand side is failing to respond to supply-side
problems. Fixed electricity prices meant household demand remained high
throughout that scorching August, with some homes running their air
conditioning all day and night. In the end, industrial usage was sacrificed to
maintain supplies for households.
‘In a situation like that, how much reserve generating capacity would we
need to ensure supplies if we don’t think about the demand side?’ asked
Yuan. Based on his calculations, adding 15 GW of reserve capacity – the
amount needed to close the gap this summer – would require a huge
investment and would only be used a few days a year. But if electricity
users were persuaded to reduce demand, the gap could be shrunk by 7 or 8
GW. Regional markets could supply 4 or 5 GW of the remainder, requiring
an investment on the supply side of only 2 or 3 GW.
Document No. 9 also calls for demand-side management to be used to
balance supply and demand. The government is to use market reforms on
both the demand and the supply side to maintain that balance.
And while the 14th Five Year Plan sets a target for demand-side
management – demand-side response mechanisms should be able to shift 3–
5% of peak load – market incentives to encourage investment in such
mechanisms are lacking. Yuan Jiahai thinks the role of the National Energy
Administration (NEA) is a major factor.
He explains that the NEA acts as a ‘power supply management agency’,
rather than improving the overall system. There is no NEA department
responsible for managing the demand side, which means that after two
power shortages, China is still working to increase supply, rather than
balance supply and demand.
So China should focus investment on electricity system reforms, build
regional electricity markets, and develop demand-side response.
As Huang Hui, manager of NRDC China’s Climate and Energy Project, and
Dr Yang Fuqiang, a research fellow at Peking University’s Institute of
5. 3 ways clean hydrogen projects can
boost their chances of securing final
investment decisions
There are many barriers preventing clean hydrogen projects from reaching
final investment decision (FID). Here, we take a closer look at the
importance of securing clean hydrogen offtake customers and share
practical solutions to overcoming this challenge.
Clean hydrogen is set to play a critical role in the energy transition, yet,
despite a growing pipeline of projects, only 4% have reached FID. To
discover what is driving this dynamic and to identify ways to remove
barriers, the World Economic Forum launched the Clean Hydrogen Project
Accelerator to understand how the pathway from announcement to FID may
be expedited. Somewhat counterintuitively, given demand forecasts,
Accelerator projects highlight that finding and securing offtake agreements
is a challenge. This is critical as it enables these capital-intensive projects to
demonstrate long-term bankability and return on investment.
So, why is it difficult to secure offtake agreements and how can this
challenge be overcome? Through the Accelerator engagements, three key
avenues were identified:
Closing the price gap between buyers and sellers
There is a sizable gap between the price expectations of clean hydrogen
buyers and sellers. Most buyers are constrained by the price of their existing
energy and a switch from grey to clean hydrogen could be multiple times
more expensive. Despite the soaring natural gas prices driven by the war in
Ukraine and increasing public and regulatory pressure, the cost gap still
prevents many companies from taking meaningful action towards net-zero.
This is a particular challenge in sectors with low-profit margins, such as
fertiliser production, where hydrogen is a critical component.
In the short to medium term, government intervention and subsidies will
play an important role in helping to bridge the price gap between buyers and
sellers, making offtake contract negotiations more attractive for both
parties. In Europe, under RePowerEU, the European Commission will roll
out carbon contracts for difference (a financial mechanism to cover the
switching cost) to support the uptake of green hydrogen by industry. In the
US, the Department of Energy has announced an USD 8 billion program to
develop regional clean hydrogen hubs under the Infrastructure, Investment
and Jobs Act and USD 270 billion for clean energy tax credits under the
historic Inflation Reduction Act, allowing green hydrogen to have a USD
3/kg subsidy advantage over grey.
At the project level, Yara Clean Ammonia, the world’s second-largest
ammonia producer, received a USD 33.2 million grant from the Norwegian
government for the development phase of its Skrei Project, a new
electrolysis plant that will tie into the existing plant for ammonia
production.
A similar approach has been adopted by JERA, the largest power generation
company in Japan. It is undertaking an ammonia procurement and co-firing
demonstration project at its Hekinan Thermal Power Station and has
leveraged government grants to reduce ammonia production costs and to
cover R&D costs until FY2024.
Dealing with supply-side risk
While over 45 giga-scale clean hydrogen projects proposals (over 1 GW of
electrolysis) have been announced, production at this scale is not yet
proven, creating significant supply-side risk. This will improve over time,
but it creates a real risk for early-moving offtakers and is particularly
unpalatable for buyers, such as public utility companies, for whom
reliability and security of supply is a matter of national interest.
To overcome this issue, two key strategies have been adopted:
One strategy is to create industrial clusters, where supply and demand are
co-located. These industrial clusters are epicentres for hydrogen activity,
coalescing stakeholders across the entire hydrogen value chain and aligning
them around common goals. This enables cluster members to source
hydrogen from multiple sources and for suppliers to take advantage of a
readily available pool of potential offtakers. The HyNet North West cluster
in the UK is a visible success story in this regard having facilitated over 24
Memorandums of Understanding for offtake. Another example is how
Mitsubishi and Chiyoda have engaged the Port of Rotterdam industrial
cluster to support their efforts in sourcing offtakers for hydrogen delivered
through their ‘SPERA’ technology. They are now in the early stages of
securing offtake within the steel, sustainable aviation fuel, chemicals and
power sectors.
The second strategy is vertical integration. A growing number of companies
are taking on multiple roles across the hydrogen value chain and others are
exploring options to become equity partners in aspects of the value chain
that are not typically core to their business. This has allowed them to act as
their own offtaker, increase control and awareness of the price premium
challenge and utilise trusted relationships. H2 Energy Europe (a joint
venture between H2 Energy and Trafigura), for example, is developing
green hydrogen in Denmark’s two key landing sites. Its approach has been
to prioritise large-scale production so that economies of scale will enable
future demand. In order to create an end-to-end hydrogen value chain, it
established a joint venture with Phillips 66 to create a European network of
hydrogen refuelling stations, combining retail and hydrogen experience to
boost hydrogen development in Europe.
Navigating uncertainty in standards and
certification
In addition to the policy clarity needed from governments, market-wide
standards and certification frameworks and tradeable guarantees of origin
are essential to alleviate uncertainty, garner investor and market confidence
and enable global trade. In other words, beyond the debates around the
colour of hydrogen (blue versus green), investors and offtakers need to
understand and compare the carbon content of hydrogen products from a
lifecycle analysis perspective. Without this security, many developers are
hesitant to invest in projects that may not comply with future regulatory
requirements and prevent them from achieving offtake.
The Enabling Measures Roadmaps for Green Hydrogen, published last year
at COP26, highlighted the need to ensure clear technical standards for
projects across the hydrogen value chain, including a common approach to
certification for carbon intensity. Through the G7, IRENA is working on a
gap analysis of hydrogen certification schemes that will provide much-
needed clarity for the industry.
There are a few instances of organizations innovating to overcome this
barrier. Yara Clean Ammonia, for example, has created its own certification
scheme that it expects will align with future standards as they are rolled out.
Although not yet internationally recognized, its introduction has been key to
providing certainty and reassurance to offtakers paying a price premium.
Where to from here?
Securing offtake contracts will play a vital role in progressing projects to
FID, but this is not the only challenge. It is critical that supply, demand and
infrastructure for clean hydrogen are scaled up jointly, and that the
underlying supply chain and required skills are developed at pace.
At the time of writing, governments from across the globe are gathered at
COP27. We need them to work together and with industry to solve
bottlenecks, establish policy frameworks and enable measures that will
