FEBRUARY 2016: Issue 104
A QUARTERLY JOURNAL FOR DEBATING ENERGY ISSUES AND POLICIES
forum
Electricity is in ferment – an unusual
state for an industry which has
traditionally enjoyed the security of longterm
assets, steadily growing demand,
and stable revenues (which has, in short,
long been the position of a typical utility).
These secure foundations are now
coming into question as the industry
faces major technological, economic,
and institutional change. Perhaps
most visible are the developments in
electricity generation – the growing
penetration of intermittent renewable
plants, driven both by technological
advances and by the policy commitment
to decarbonization. But signiﬁcant shifts
are also taking place elsewhere in the
system with the rapid development of
information and control technology,
which is opening the way for new
approaches to system management and
more ﬂexible demand. It is likely that we
are only seeing the beginnings of these
changes – they raise wider questions
about the very nature of the industry’s
product and its relationship with its
customers.
The technological developments have
been accompanied by major policy
and economic changes – falling
electricity demand, greater use of
on-site generation leading to lower
network income, governments rather
than markets driving investment in both
renewable and fossil generation, and
so on. The institutional frameworks
surrounding the industry are struggling
to keep up. For two decades or so
after 1990, governments across the
world focused on liberalization and the
extension of market forces; now there
is a new emphasis on decarbonization,
but governments have not yet worked
out whether decarbonization and
liberalization can go hand in hand
or whether there is a fundamental
conﬂict. Markets have also been slow
to adapt to the new era – the industry
has traditionally relied on marginal
cost (kWh) pricing, although a large
proportion of its costs have always
been ﬁxed (and some eminent
economists like Ronald Coase have
argued against the over-emphasis
on marginal cost). With a growing
penetration of zero marginal cost
plants, the marginal cost approach
looks increasingly outdated, whether
at wholesale or retail level. Regulation
too needs to respond to the changes –
including the increasing decentralization
of the system – under way. New
coordination and control methods
may be required to manage the rapid
growth of intermittent generation,
particularly wind. Indeed the whole
basis of the industry’s workings is
coming into question: what ultimately
are its products? How should it price
them? What business models should
the industry be developing? What are
OXFORD ENERGY FORUM
CONTENTS
Transformation of the Electricity
Sector: Technology, Policy and
Business Models
Future business models for power markets:
what can we learn from the ‘sharing economy’?
Rolando Fuentes 5
How the ‘Big Beyond’ will change business
models of utilities
Christoph Burger and Jens Weinmann 8
Renewable integration and the changing
requirement of grid management in the
twenty-ﬁrst century
Rahmat Poudineh 11
Market integration with energy-only markets
and renewables: lessons of experience from
Australia
Rabindra Nepal and Tooraj Jamasb 14
Reforming European electricity markets for
renewables
Richard Green and Goran Strbac 17
Supporting renewable generation in the UK
David M. Newbery 19
Centralized or decentralized? Remove ﬁrst
the regulatory barriers
Ignacio Pérez-Arriaga and Scott Burger 22
Wind power and electricity supply security
in Colombia
David Harbord, David Robinson, and Iván M. Giraldo 26
Decarbonization through electriﬁcation – the
importance of energy taxation being in line
with long-term energy policy
Graham Weale 29
View from the USA: rapid transformation of
power sector calls for new tariffs
Fereidoon P. Sioshansi 33
A comparison of US and EU electricity prices:
the relevance of the government wedge
David Robinson 35
Assessment of demand response in Shanghai
Malcolm Keay, Xin Li, and David Robinson 40
Power system reform to enable large-scale
wind utilization in China
Zhang Xiliang and Xiong Weiming 43
INTRODUCTIONTOTHISISSUE
its resources and how do storage and
demand response ﬁt in?
These fundamental questions underlie
many of the articles in this issue of
the Oxford Energy Forum. One theme
is the need to look at basic business
models. Rolando Fuentes considers the
impact of distributed energy resources
(DER) such as solar panels, batteries,
smart meters, and appliances, which
are together acting as disruptive
technologies. Using two examples
of successful business models from
the ‘sharing economy’ – UBER (taxi)
and Airbnb (room letting) – the author
identiﬁes three big issues for the
power sector: the reallocation of risk,
the paradoxical role of price signals
in situations of spare capacity, and
the dynamics between regulation and
business models. He argues that,
contrary to the current situation in
which electricity regulation dictates
the business model of utilities, new
business models can shape future
regulation; by re-allocating risks, a
new role can be created for incumbent
utilities. Fuentes also proposes that
electricity markets need to be redesigned
to take into account the
multidimensional nature of electricity
and distinguish between separate
services such as reliability (MW),
energy (MWh), system savings (NWh),
and environmental beneﬁts (carbon
dioxide emissions reductions).
Christoph Burger and Jens Weinmann
also look at the implications of the
growth in renewable generation for
business models, particularly in
Germany. Germany is in many ways
affected by the issue more acutely
than other countries, both because
it has seen such a rapid increase in
generation from wind and solar PV,
and because in Germany little of this
new generation is owned by the main
utilities themselves. Those utilities are
therefore facing a major erosion of
their revenues and need to come up
with imaginative responses – a difﬁcult
task for companies used to more
conservative ways of thinking. However,
they are exploring new approaches,
like outsourcing innovation and
promoting co-investment and venture
capital funds. But the long-term
challenges posed by IT may be even
more fundamental – challenges such
as the Internet of Things, the sharing
economy, and the use of blockchains
to squeeze out intermediaries.
Integration of the new sources and
system coordination are the focus of a
number of articles. Rahmat Poudineh
discusses the new requirements for
grid management that result from
the integration of renewable energy
resources. In recent years supply side
ﬂuctuations, mainly related to wind and
solar power, have presented a new
form of uncertainty to the power system
and added to the complexity of grid
management. Power systems with a
lot of renewables tend to experience
short and steep ramps, such that the
system operators need to bring on or
shut down power plants more often
than in the past, and within very short
periods of time. He contends that
as intermittency increases and the
need for ﬂexibility becomes critical,
the system will require new models of
grid management both at operational
and institutional levels. In addition
to traditional resource adequacy
metrics we need new methodologies
to quantify and assess the technically
available operational ﬂexibility of the
power system. In addition, he argues,
we need to ensure that electricity
markets and regulations not only
provide incentives for investment
in ﬂexible resources but also make
efﬁcient use of available resources.
Rabindra Nepal and Tooraj Jamasb
discuss the experience of market
integration, renewable energy, and
network regulation that has been
built up by the Australian National
Electricity Market (NEM). They provide
an overview of the structure and
organization of the NEM and point
out that, more than 14 years since the
establishment of the NEM, wholesale
electricity price differences persist
across the Australian states. The main
reason for this is the presence of
network constraints across the regional
interconnectors, which impedes
the wholesale market integration
process in the NEM. In addition,
the authors argue that the lack of
adequate interconnection prevents the
development of new wind power in the
resource-rich regions and leads to the
curtailment of the existing capacity.
The costs in terms of lost revenue
to wind power plants as a result of
curtailment are large and hamper
meeting the national renewable
energy targets. Therefore, the authors
contend that the development of
renewable energy and electricity market
integration can be complementary
policy objectives in the NEM as one of
the largest interconnected energy-only
markets in the world.
Richard Green and Goran Strbac
explore ways of adapting European
electricity markets for renewables.
The authors argue that national
renewable energy policies in the EU
region are still uncoordinated, and the
concentration of renewables in more
favourable locations would bring
important savings. Additionally, they
argue that the existing linkages
between day-ahead markets need to
be supplemented with greater
coordination on longer and shorter
timescales. Short-term balancing
costs could be reduced if system
operators had access to balancing
services and reserves in neighbouring
systems. Cross-border trading of
long-term contracts for energy would
be facilitated by the use of Financial
Transmission Rights (FTRs), which do
not have the restrictions of capacity
contracts. They also suggest that in
order to facilitate balancing between
countries, we may have to integrate
TRANSFORMATION OF THE ELECTRICITY SECTOR
2 OXFORD ENERGY FORUM
energy and reserve markets within
each country – something that the
American experience shows can be
done. However, the political
challenges involved in creating a good
market design should not be under-
estimated.
Regulation and government policy also
need to be addressed. David Newbery
examines the logic, drawbacks,
and possible resolutions of the EU
Commission’s proposed shift from
feed-in tariffs (FiTs) to Premium FiTs
(PFiTs), for future UK renewables
support. The author reviews the
history of UK renewables support and
argues that an important advantage
of quantity-based instruments like
Renewable Obligation Certiﬁcates
(ROCs) is that their cost is controllable.
However, ROCs are exposed to
volatile market prices and abundant
renewables deployment can depress
their prices. In contrast, a ﬁxed FiT
provides greater insurance but at the
same time risks excessive demand
and budgetary cost, if no cap is set on
the total quantity procured. From the
author’s point of view, the question is
how to combine the advantages of a
PFiT with the risk-reducing properties
of a FiT. Newbery argues that capacity
contracts with suitable Power Purchase
Agreements (PPAs) and contracts for
ancillary and balancing services (with
all contracts reﬂecting efﬁcient market
value) are the logical solution and
should support the delivery of lowcarbon
electricity at least cost.
Ignacio Pérez-Arriaga and Scott Burger
address the regulatory challenges
related to the growing penetration
of distributed energy resources
(DER) such as: gas-ﬁred distributed
generation, solar PV, small- and
medium-sized wind farms, electric
vehicles, energy storage, and demandside
management. The fundamental
question is what role should be played
by DER, and what by conventional
centralized energy resources. They
argue that current regulations are
woefully inadequate to meet the
incoming challenges and that what
is needed is an in-depth review and
corresponding modiﬁcation to create
an economically neutral playing ﬁeld,
enabling centralized and decentralized
resources to compete and collaborate
efﬁciently, while recognizing that they
perform under very different conditions.
This regulatory review should apply
the fundamentals of microeconomics
to power systems in order to do the
following: reconsider the deﬁnition
of ‘essential electricity services’;
examine how to compute prices so that
economic efﬁciency is maximized; and
understand what, if any, is the value
that aggregation of DERs and any
associated business models bring to
the power system.
David Harbord, David Robinson, and
Ivan Giraldo illustrate how the energy
regulatory regime in Colombia acts as
a barrier to investment in wind power.
The Colombian electricity system
relies very heavily on hydro power.
However, during El Niño (dry) weather
periods, hydro-based generation
falls signiﬁcantly. Consequently, the
regulatory system has been designed
to ﬁnance the building of generation
capacity that can substitute for hydro
during dry periods. The regulator
organizes auctions to select the
plants that will be awarded long-term
contracts to provide backup, and to
determine the price for ‘ﬁrm energy’.
A critical issue has to do with how
much ﬁrm energy is attributed to
different technologies in the auctions.
The authors argue that the current
methodology underestimates the
amount of ﬁrm energy available from
wind power because it does not
adequately reﬂect the evidence that
wind generation is greater when it
is most valuable, speciﬁcally during
El Niño periods. Since secure longterm
revenues are directly related to
the amount of ﬁrm energy sold in the
auction, the regulations therefore act as
a barrier to investment in wind power.
Electricity pricing and taxation are
facing major new challenges. Graham
Weale considers a signiﬁcant policy
consistency. On the one hand,
governments see electricity as the
main vector of decarbonization, via a
greatly enhanced role for decarbonized
electricity within energy supply. On the
other hand, current taxation policy is
hindering the process of electriﬁcation
by loading more tax and surcharges
on to electricity than on other energy
sources – in Germany, taxes and
surcharges on electricity for electric
vehicles are actually higher than taxes
on vehicle fuels. One result is that in
many countries, electricity’s market
share is actually starting to decline.
Weale considers various options for
bringing energy taxation into line with
overall energy and climate policy.
Covering the costs of decarbonization
from general taxation seems like a
logical solution but it raises many
political difﬁculties – the important
thing is to recognize and address the
problem.
Fereidoon Sioshansi looks at the
implications of the changes under way
in the power sector for the structure of
electricity tariffs, focusing on the USA.
Most consumers there pay on a
volumetric (kWh) basis. This means
that utilities lose income when
consumers install on-site generation,
such as rooftop solar PV, and as a
result buy less from the grid. To make
up for the loss of income, utilities may
be forced to raise their tariffs – thus
further encouraging investment in
energy efﬁciency and on-site
generation and leading to the
so-called utility ‘death spiral’. The
process leads to a shift of costs from
customers with solar generation to
customers without, raising signiﬁcant
equity issues and pitting the two sets
of customers against each other.
Sioshansi considers various possible
INTRODUCTIONTOTHISISSUE
FEBRUARY 2016: ISSUE 104
3OXFORD ENERGY FORUM
solutions, such as three-part tariffs,
increased ﬁxed charges, time-of-use
rates, and demand subscriptions, but
concludes that ‘the battle is just
beginning’.
David Robinson analyses the reasons
why ﬁnal electricity prices in the EU
have risen so much faster than in
the USA since 2008. This cannot be
explained by different trends in costs
related to wholesale generation,
transmission and distribution
networks, and retail services. Rather,
it reﬂects the increase in the EU of a
‘government wedge’ in ﬁnal electricity
prices. This wedge includes taxes
and levies related to the ﬁnancing of
decarbonization, and also support
for domestic fuels (such as coal),
subsidies for speciﬁc consumer
groups, and other policy objectives.
In short, ﬁnal electricity prices in many
EU countries no longer reﬂect the
costs of supply, but rather the costs of
meeting a variety of policy objectives.
This has distributional consequences
and hurts the competitiveness of many
industrial and commercial consumers.
Furthermore, it introduces economic
distortions – which include an incentive
for consumers to favour fossil fuels
over electricity. He makes a number
of policy recommendations, including
the introduction of carbon taxes and
shifting some of the policy costs to the
government budget.
Finally, two articles look at experience
in China, which is facing challenges
similar to those elsewhere in the world
in relation to integrating the new
resources, and is responding via a
move to greater reliance on economic
signals and market mechanisms.
Malcolm Keay, Xin Li, and David
Robinson report on a study
undertaken by the OIES, along with the
Environmental Change Institute of
Oxford University, on the potential for
demand response in Shanghai. While
interest in demand response is
growing worldwide, examples from
outside the OECD are often less
familiar. Furthermore, the Chinese
electricity system presents many
special characteristics, in particular
the widespread use of a form of
administrative demand control to
balance the system. Nonetheless,
China is moving towards a greater
reliance on economic instruments in
electricity, as in other sectors, and the
Shanghai study aimed to establish
whether demand response could have
a role there, as elsewhere. It showed
that there is indeed potential for this
approach, which could have both
economic and environmental
advantages, and the issues involved
are now being examined in more detail.
Zhang Xiliang and Xiong Weiming
analyse the signiﬁcant curtailment of
wind power in China. Although China
has become the largest wind power
market in the world, in the ﬁrst half of
2015 over 15 per cent of technically
available wind power could not be
connected to the grid and had to
shut down. The reasons include
uncoordinated planning between the
grid and the wind generators, inﬂexible
dispatch, and the lack of suitable
policy incentives for stakeholders,
notably the grid operator and the coal
power generators. The government
has introduced a number of policy
reforms, but the curtailment problem
remains serious. In May 2015, the State
Council released Document 9, which
could be the basis for deeper reforms
of the power sector. It emphasizes the
role of market mechanisms, especially
in generation and retail segments,
and also stresses the importance of
integrating renewable energy in order
to facilitate decarbonization, improve
air quality, and mitigate climate change.
The authors conclude that the best
way to solve the problem of curtailment
of wind power is to introduce market
mechanisms, such as a spot market,
as well as policy incentives for key
stakeholders.
INTRODUCTIONTOTHISISSUE
TRANSFORMATION OF THE ELECTRICITY SECTOR
4 OXFORD ENERGY FORUM
Future business models for power markets: what can we learn from the
‘sharing economy’?
Rolando Fuentes
Innovations in distributed energy
resources (DER) − like solar panels
and batteries, information technologies,
smart meters and appliances − have
the potential to rock the fundamentals
of the electricity sector. It now seems
likely that a signiﬁcant proportion of
future end-use electricity consumption
could be supplied and managed by
relatively small-scale, distributed
resources, opening up attractive
alternatives to traditional utilities for
customers. This shift could reduce
reliance on the central grid, which
could ultimately change the way
electricity is purchased, transported,
and consumed. Boundaries between
transmission–distribution and
distribution–commercialization and
generation may become blurred, as
these activities would occur in the
same place: the household. However,
the system would become more
complex, since households are
geographically dispersed.
‘…A SIGNIFICANT PROPORTION
OF FUTURE END-USE ELECTRICITY
CONSUMPTION COULD BE SUPPLIED AND
MANAGED BY RELATIVELY SMALL-SCALE,
DISTRIBUTED RESOURCES…’
The arrival of these innovations is
leading utilities around the world to
re-evaluate their business models, and
regulators are considering electricity
market reforms. However, trying to ﬁx
the system with marginal or incremental
amendments will not be sufﬁcient to
cope with all these changes. In this
article we explore experiences gathered
from other industries that have faced
technological disruptions recently,
together with lessons they have learned
which might guide future business
models in the power sector.
Value proposition
There are at least three reasons to
revisit business models.
1 These technological disruptions make
it more evident that electricity is a
multi-dimensional commodity, the
attributes of which at times may be
difﬁcult to price. For example, bound
up with the energy service itself are:
efforts to reduce emissions, reliability
services, and risks. Also, the nonconsumption
of power has a value to
the system. A key question for future
business models then is how to
monetize these values.
2 This eruption of innovative new
technologies is taking place in a
sector that has sunk costs and where
investments are already in place. Hence
the power sector cannot start afresh.
3 There is a place for both utilities and
new entrants in the industry, albeit
with different roles.
The prevailing business model for
electricity utilities is a cost-plus structure
in which the utilities pass their costs,
plus a return on their capital investment,
to customers at a variable rate (USD/
kWh). The objective is to operate in a
cost-minimization fashion and the model
sustains itself with further capital
investments, sales growth, and
sustainable prices. This has led to the
development of a business model where
adding new capacity is the bread and
butter of utilities’ revenues. But should
we still impose this framework on utilities
in the future, given massive investment
requirements and lower sales?
There is a legacy in the power sector
and the impact of the adoption of these
technologies could go either way, with
a positive or a negative impact.
Uncoordinated introduction of DER
could increase system risks and
transfer costs to other customers, in the
absence of an organized market.
However, so long as these newer
technologies operate in a coordinated
way with the other power sector
resources, they can provide value to
customers and to the overall system.
Also, the value delivered by distributed
technologies together would be greater
than the sum of the values delivered by
individual components.
These facts lead us to posit different roles
for incumbent utilities and for new
entrants. A utility offers not only energy to
its customers but also spare generation
capacity, ramping ﬂexibility, operating
reserves, spare distribution capacity,
and ancillary services. But customers do
not value all these items in themselves,
since they don’t see them or think about
them. Rather they value the services
that depend on them – for example,
reliability – from their power provider.
Airbnb and UBER
It has been suggested that solar
photovoltaic (PV) panels, batteries, and
smart grids can essentially transform the
power markets into a series of nested
markets, connected through different
platforms as if they were multiple-sided
markets. According to an IDEI (Institut
D’Economie Industrielle) working paper of
2004 – ‘Two-Sided Markets: An Overview’
by Jean-Charles Rochet and Jean Tirole
– a multiple-sided market is a meeting
place for a number of agents that interact
through an intermediary or platform.
Markets of this sort, such as credit card
companies and stock exchanges, have
become prevalent in today’s economy.
Google Search, Amazon, Facebook,
UBER, and Airbnb are just a few of the
more prominent examples. In these types
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5OXFORD ENERGY FORUM
of markets, according to the EPRG
(Energy Policy Research Group) working
paper ‘Platform Markets and Energy
Services’ of 2013 by Claire Weiller and
Michael Pollitt, an intermediary captures
the value of the interaction between user
groups, and network externalities may
lead to one of them being charged a non
cost-reﬂective price.
‘THE VALUE PROPOSITION OF THE
SHARING ECONOMY BRINGS TOGETHER
OPERATORS WITH UNDERUSED ASSETS…’
The UBER (taxi) and Airbnb (room
letting) business models – two
successful companies of the ‘sharing
economy’, as it has come to be
known – may help us understand the
future business models of the power
generation sector. We can draw three
lessons from the sharing economy
experience. The ﬁrst is that risk is
re-allocated across the market, the
second is the paradox between spare
capacity and price signal, and the
third relates to the dynamics between
regulations and business models.
The value proposition of the sharing
economy brings together operators with
underused assets and others that may
wish to hire or rent, in a timely manner,
with low transaction costs since their
information is more transparent due
to the use of an internet platform. The
businesses of the sharing economy set
out to optimize the use of resources by
making more frequent use of excess
capacity in goods and services.
According to an Economist article (‘The
Rise of the Sharing Economy’) in March
2013, other terms that have been coined
in the media for this sector are the
‘collaborative economy’, the ‘asset-light
lifestyle’, or the ‘access economy’.
Risk-reallocation
One of the key elements of the UBER
or Airbnb business models is the need
to deal with the uncertainty buyers and
sellers have in sharing and trading with
people they have never met. Thus, as a
side effect, insurance companies have
gained from this model as more people
demand their service. Borrowing this idea,
an incumbent utility could act as the
insurer of the rest of the power sector. As
more renewable energy is installed and
operated, this would mean two things:
a growing share of generation would be
at zero marginal cost, and utilities could
end up with unused capacity for long
periods of time. Paradoxically, that would
make traditional capacity more important
system-wise, as the incumbent would be
the operator of last resort to keep the
lights on. Consequently, the beneﬁt of
maintaining the grid’s operability with the
costliest energy source would outweigh
the cost of the absence of electricity.
If utilities are to use their infrastructure
as insurance, they will need to change
the way they charge customers. A
health insurance company’s business
model, for example, is based on
healthy people ﬁnancing treatments
for ill people. The way forward for the
utility could be to charge a ﬁxed price,
like an option value, for back-up. This
would compensate for the long periods
of zero marginal cost generation that
could undermine the energy service
their installed capacity provides, but not
the reliability component provided by
the same capacity. Utilities could offer
memberships, or stream services like the
internet television network Netﬂix, where
customers pay a ﬁxed amount. Or energy
providers could offer contracts of service
for electricity ‘on demand’, which would
be more expensive, or ‘as available’,
based on solar or other intermittent
renewable generation (according to the
chapter ‘Electricity markets and pricing
for the distributed generation era’ by
Malcolm Keay, John Rhys, and David
Robinson in Fereidoon P. Sioshansi’s
2014 book Distributed Generation and
its Implications for the Utility Industry).
This option would detach power prices
from the time variable. The alternative
would run contrary to the recent
tendency to have more real-time
decisions with smart metering, as it
would decrease the number of
transactions and increase the time
period during which they take place.
Counterintuitively, this option would
increase the time lags of transactions by
charging ﬁxed prices for coverage in
longer periods. However, ﬁxed prices
have been met with signiﬁcant resistance
from energy efﬁciency and DER
advocates, because customers would
no longer have the incentive to adopt the
new technologies and thus save money.
There are two caveats. First, as is often
the case, the starting point matters.
For example, people are willing to pay
for health insurance to increase their
coverage, whereas customers of the
power sector start with near 100 per
cent coverage already. In complete
energy autonomy they would need to get
used to paying for a service that they are
accustomed to receiving and taking for
granted, alternatively, they would need to
demonstrate their willingness to accept
occasional service disruptions. Second,
contracts for stream services like Netﬂix
are feasible since there is no rivalry in
consumption in their stream service.
Electricity is a rival good in consumption,
but it can still be argued that not all of the
utility’s customers will need back-up at
the same time, just as not all people claim
on their health insurance or cash-in their
bank accounts at the same time.
Spare versus scarce
There is a paradox in the sharing
economy model. The traded asset is
usually idle capacity − for example,
Airbnb’s asset is unused rooms in
people’s houses − whereas economic
theory focuses on how prices send
scarcity signals. The question is: what
are the spare, and what are the scarce,
assets in the new electricity sector
structure? It may be that the abundant
asset will be PV solar panels. One of the
concerns is that PV ends up completely
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6 OXFORD ENERGY FORUM
ﬂooding the electric power system with
uncontrolled amounts of zero variable
cost energy. The scarce resource is
more difﬁcult to work out. However,
bearing in mind the nature of the new
technology, the distribution sector, the
multidimensional characteristics of
products and services in the power
markets, and the network effects, we
foresee the following:
Average cost per kW will be lower. A
recent multidisciplinary MIT study
(‘The Future of Solar Energy’, 2015)
shows that a large penetration of
solar PV displaces the plants with the
most expensive variable costs and
increases the cycling requirements of
thermal plants.
The role of energy aggregator will be
more widely seen. If generation is
intermittent, dispersed, and uncertain,
what business ideas can ameliorate
these undesirable characteristics?
The answer lies in the creation of a
relatively new player in the market:
the aggregator. The aggregator’s
function would be to coordinate the
loads from dispersed sources, thus
smoothing out the underlying
intermittency. These new players are
already emerging in California.
Indirect services will be central to the
new electricity markets. Electricity
has multidimensional attributes. The
most straightforward is the quantity
of energy delivered at speciﬁc times
and locations. But we can also
consider the purpose for which the
electricity is used. For example:
charging a battery, running a fridge,
watching TV, end-use, cooling, and
heating. And we should consider its
reliability − the probability that supply
would be available. Firms can sell
reliability (MW), energy (MWh),
system savings (NWh), or
environmental beneﬁts (carbon
dioxide emissions reductions).
Managing demand proﬁle is key for the
new marketplace: the distribution. One
of the main determinants of distribution
operations is demand proﬁle. How can
business solutions, to some extent,
help to manipulate demand proﬁles
so that non-consumption and
demand response become valuable?
A key issue would be how to price
these services, as most of them are
externalities – positive and negative.
There are a couple of alternatives:
Regulation that imposes values,
products, and transaction guidelines.
Such regulation would establish the
rules of the markets, while the
markets themselves would then
decide the efﬁcient level of provision.
A Coasian approach where
governments assign property rights,
for example over the reliability aspect
of the system, and permit actors to
trade between themselves.
Regulatory dynamics
Utilities’ business models have largely
been dictated by their regulatory model.
It is true that the rate-of-return regulation
in some countries has made the utility
business model an infrastructure one.
But in other regulated industries where
technological innovation has changed the
landscape, regulation has proved to
have been lagging behind the impetus
of the industry. One of the most notable
cases where regulation has been forced
to adapt to these technologies is in the taxi
services industry, with the advent of UBER.
In such a case, the dominant strategy
for a new entrant – UBER, or Airbnb,
for example – is to quickly grab market
share to lock in their platform. This would
force regulators to accommodate these
new business practices as the standard
regulation. For example, regulators have
taken a hands-off approach with regard
to risks for new taxi services and have
chosen to include insurance clauses
as part of their regulation. This was
adapted from UBER’s own business
model. Other jurisdictions facing similar
problems are likely to follow what the
ﬁrst mover regulators have done. This
will then become the norm. Having a
homogenous regulation framework helps
new companies expand more rapidly
across different cities or countries.
A key element for the electricity
generating industry is this chicken
and egg question: will penetration of
distributed energy resources occur in
an orderly manner, allowing regulators
to accommodate them? Or will new
entrants and new business models in the
end pre-empt future regulation?
Conclusion
Business models in the electricity
sector have been under scrutiny. In
this article we try to draw parallels
from industries that partially resemble
the power sector and that have faced
recent technological disruptions.
The main points we can draw from
those are:
1 technical disruptions will force
regulations and business models to
adapt;
2 business models can shape future
regulation, as opposed to the position
at present where regulation dictates
the business models for utilities;
3 re-allocation of risks opens up the
prospects of a new role for the
incumbent utility; and
4 electricity has multi-dimensional
attributes for which markets need to
be designed.
This article is based on a forthcoming
KAPSARC publication
‘THE AGGREGATOR’S FUNCTION WOULD
BE TO COORDINATE THE LOADS FROM
DISPERSED SOURCES, THUS SMOOTHING
OUT THE UNDERLYING INTERMITTENCY.’
‘WILL PENETRATION OF DISTRIBUTED
ENERGY RESOURCES OCCUR IN
AN ORDERLY MANNER ALLOWING
REGULATORS TO ACCOMMODATE THEM?’
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7OXFORD ENERGY FORUM
Challenges of energy incumbents
According to ﬁgures from the German
environmental ministry, Germany
increased its intake of renewable
energies from 6 per cent in 2000 to 32.5
per cent in the ﬁrst half of 2015. The
country’s incentive system, based on
ﬁxed feed-in tariffs, motivated private
individuals such as homeowners,
farmers, and energy associations to
participate in the market. In 2014,
around half of all renewable energy
installations were owned by citizens,
rather than corporate entities, and more
than 1.5 million producers of electricity
participated in the market.
‘IN 2014, AROUND HALF OF ALL
RENEWABLE ENERGY INSTALLATIONS
WERE OWNED BY CITIZENS, RATHER
THAN CORPORATE ENTITIES…’
In contrast, the ‘Big 4’ energy
incumbents operating in Germany
– EnBW, E.ON, RWE, and Vattenfall
– own less than 10 per cent of all
renewables installations. One of the
reasons why incumbents have not
participated in the rush for renewable
energies may be that their business
model has traditionally been directed
towards large-scale projects, rather
than smaller, decentralized installations,
given that the proportion of transaction
costs involved in small-scale
investments is typically higher than in
larger projects.
Since the marginal costs of sun and
wind power are practically zero, the
priority feed in of renewable energies
has induced a downward pressure
on prices in the German wholesale
market. Average peak load prices have
decreased from around 60 EUR/kWh in
2011 to less than 35 EUR/kWh in 2014,
according to the Fraunhofer Institute
for Solar Energy Systems (ISE). E.ON,
the largest German electricity producer,
posted a loss of EUR5.7 billion for
the ﬁrst nine months of 2015, while
competitor RWE’s operating result
decreased by 9 per cent. The erosion
of revenues has led to a strategic shift
being undertaken by E.ON and RWE.
Both utilities intend to split their assets
into two separate and independent
entities, with the intention of
reorganizing their activities and creating
companies that are able to ﬁt better into
the changing marketplace.
Counter-strategies and new forms of
innovation
Many European electric utilities that
are exposed to similar developments
have realized that their business model
has to change if they want to survive
in the competitive environment. They
have to become more innovative
and explore new business models to
compensate for the loss of revenues
in their traditional business units. In
the past, research and development
within utilities predominantly focused
on incremental innovation, on the
gradual improvement of processes and
operations, rather than on disruptive
business ideas. Utilities with a retail
and distribution business have a
particular advantage in the testing of
new business models, because they
are already physically present on
the premises of their customers, via
metering technology.
‘MANY EUROPEAN ELECTRIC UTILITIES …
HAVE REALIZED THAT THEIR BUSINESS
MODEL HAS TO CHANGE IF THEY WANT
TO SURVIVE…’
However, utilities struggle to ﬁnd
people within their workforce that are
capable of developing genuinely new,
customer-centric, digital business
models. Hence, they follow a strategy
that has proven successful in many
other industries, as diverse as
pharmaceuticals, logistics, or ﬁnance,
over the last couple of years. They
outsource innovation to young teams
of entrepreneurs and the founders of
new companies. The most common
instruments of that process are venture
capital (VC) funds, incubators, and
accelerators. VC funds typically provide
ﬁnancial resources to a portfolio of
small companies, but they do not
interfere with the day-to-day operations
of their ventures. By contrast, corporate
incubators provide an environment (but
not necessarily a physical location)
where new ideas from inside or outside
the company are nurtured, protected
from the company’s other key
performance indicators and standard
corporate culture. Accelerators, the
third common type of these new forms
of innovation, are programmes of two
to six months duration in which a team
of mentors and coaches guides the
founders of new companies through
the process of developing a business
plan and of ﬁnding investors to
commercialize their ideas.
Hybrid forms of business model are
also possible: E.ON, Germany’s
largest utility, pursues a strategy
of co-investments where (limited)
involvement and early bonding
between a business unit (which takes
over some type of ‘ownership’) and the
venture is desired.
As early as 2008, the Spanish energy
utility Iberdrola began setting up a VC
fund and through to 2015 most major
European players followed – either
establishing their own organizations
or participating in collaborative efforts
How the ‘Big Beyond’ will change business models of utilities
Christoph Burger and Jens Weinmann
TRANSFORMATION OF THE ELECTRICITY SECTOR
8 OXFORD ENERGY FORUM
with other companies. The diagram
below shows a selection of initiatives
undertaken by major European energy
incumbents.
Three major challenges emerge with
this type of diverse innovation:
1 The multitude of ideas implies that a
large fraction of these start-ups and
ventures will not succeed in the
marketplace. A venture capital ﬁrm
typically receives 2,000 business
plans, evaluates 200, and invests in
20, of which roughly 2, or 10 per cent,
outperform – a chance of 1:1,000 to
identify a successful business model.
The ‘fail-fast’ attitude is an inherent
characteristic of the start-up
ecosystem, but it requires a
fundamental change in mentality of the
top management of electricity utilities.
2 Integrating the ventures into existing
organizational structures is most likely
to succeed when done early. For
example, German incumbent E.ON
tries, very early in the process, to
identify business units that will take
‘ownership’ of idea and start-up.
3 Will the new ventures yield sufﬁcient
revenues soon enough to
compensate for losses in other units,
thus ensuring corporate survival? The
US company IBM is a prime example
of a company that can reinvent itself,
but many other incumbents from
other industries have disappeared.
Polaroid, Kodak, and DEC are just
some examples.
Not all seems lost for the electricity
supply industry. While revenues
from generation decline, the gridrelated
business of utilities (electricity
transmission and distribution) secures
a regulated (and capped) but stable
stream of income. Utilities that
own parts of the grid are in a more
comfortable position than those that
have been forced to unbundle or to
create separate legal entities.
In the longer term, however, the
grid-related services of utilities may
be threatened in the same way as
their generation business. Electricity
can now be generated at the point of
consumption, not just in centralized
power plants, while costs of renewable
energy installations have substantially
decreased over the last couple of
years. The European Union’s research
unit, the Joint Research Centre,
foresees electricity generation costs of
around 0.02 EUR/kWh for photovoltaic
installations that have already been
written off; this is cheaper than any
conventional generation technology
except large hydropower. At a retail price
of around 0.30 EUR/kWh for residential
consumers in Germany, 0.28 EUR/kWh
could potentially be spent on battery
storage or other means to detach
individual customers from the grid.
The ‘Big Beyond’
Three overarching trends, which the
authors call the ‘Big Beyond’, may lead
to an erosion of the market position of
incumbents, even in the regulated parts
of their operations:
1 Frugal innovation and the Internet of
Things (IoT) – a low-cost alternative
to conventional solutions, especially
in building efﬁciency;
2 The blockchain – a secure
transaction technology for smart
contracts;
3 The sharing economy – creating
own networks, for example via
ﬁnancing but also operating.
Frugal innovations are innovations
that are made at lower cost and lower
complexity than standard solutions.
Often they can be found in the
context of developing economies,
where many products used in the
industrialized world are too expensive
and over engineered. But even in
wealthy countries, digitalization
creates opportunities for founders and
entrepreneurs to develop solutions
for market segments that have been
untapped, often in so-called legacy
markets. Retroﬁtting existing building
stock and increasing the energy
efﬁciency of houses is one of the
areas where frugal innovation takes
place. Envio Systems, for example, is
a Berlin-based start-up that intends
to revolutionize existing commercial
buildings. The company has developed
Timeline of exemplary initiatives of selected European utilities in the
ﬁeld of ‘diverse’ innovation
Source: based on C. Burger, S. Pandit, and J. Weinmann (2015). ESMT innovation index 2014 – electricity supply
industry: The ‘big beyond’, ESMT Business Brief No. BB–15–01, (Figure 7).
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9OXFORD ENERGY FORUM
a box called Cube that contains
multiple sensors and connects to a
digital optimization platform. In contrast
to, say, Google’s residential building
efﬁciency device Nest, Cube is able
to detect whether there is anyone in a
particular room, via a carbon dioxide
sensor, and can adjust the heating
or cooling activity accordingly. Envio
System’s solution costs a quarter of
similar installations offered by large
competitors, such as Schneider
Electric, Siemens, or Honeywell. The
company estimates the market size
in North America and Europe at more
than 10 million commercial buildings.
If newcomers like Envio use the
enhanced capabilities of devices
connected via the Internet of Things,
utilities operating in retail may lose
revenues from an increasing number
of lucrative commercial customers.
Going one step further, if costs for
batteries continue to decrease and
storage becomes affordable on a larger
scale, commercial, industrial, and even
residential customers may decide to
rely completely on self-production.
The blockchain is a secure transaction
database that is currently used for
cryptocurrencies such as Bitcoin.
Due to its conﬁguration, it records
all transactions ever executed in a
transparent, decentralized internet
protocol. Its main differentiating driver
is that it can replace all intermediary
institutions whose existence is primarily
justiﬁed by their trustworthiness for
all parties involved in the transaction.
Banks belong to that group of
intermediaries, but so do energy utilities
acting as retailers or traders.
This technology may be particularly
attractive in developing countries,
where the poor often have no bank
account and could potentially use the
platform as a means to pay their bills.
For example, South African start-up
Bankymoon has introduced a system
that allows users of smart meters to
pay via the cryptocurrency Bitcoin,
thereby bypassing banks.
New venture Grid Singularity intends
to use the blockchain to introduce a
decentralized energy data exchange
platform. This would offer services
enabling forecasting for grid balancing
and would facilitate investment,
the trade of green certiﬁcates, and
eventually energy trade validation. Grid
Singularity’s founders expect immense
infrastructure cost savings, compared
to standard technical solutions that
require a fully independent vertical
integration for each energy market
operation. The platform may also
render some of the current key entry
barriers to energy trade obsolete – such
as a need to have special accounts
and deposits, or a certiﬁcation with
an intermediary ﬁnancial institution.
The business model of utilities may
be threatened if decentralized energy
producers enter into direct interaction
with their consumers. Any type of
physical or monetary transaction that
involves a trustworthy intermediary
could be replaced by the blockchain.
The third element in the ‘Big Beyond’ is
crowdfunding, which is part of the
so-called sharing economy: exclusive
ownership of goods has become less
important for young people. The prime
example is car-sharing services, where
people rent cars for a limited amount of
time. The service – in this case,
travelling from A to B – is the only factor
that counts. In the energy sector, founders
promote their business idea on
crowdfunding websites to collect money.
Companies such as crowdEner.gy,
econeers, Trillion Fund, or SunFunder
establish a parallel market that relies on
the ﬁnancial commitment of many
individuals, rather than on any bank or
single investor. For example, the German
crowdfunding company econeers
requires a minimum ﬁnancial involvement
of EUR250 over ﬁve years; investors
receive dividends and are ﬁnancially
rewarded if the venture or project is
proﬁtable. In 2015, econeers received
EUR750,000 in solar crowdfunding.
Berlin-based start-up Sunride takes
the sharing economy one step further
and implements software solutions
to optimize neighbourhood-level
photovoltaic installations that are
jointly owned and used by inhabitants.
In Berlin, more than 120 local
associations have been founded to set
up solar panels and generate electricity
for self-consumption and grid feed-in.
The ‘Big Beyond’ and exemplary companies
Source: based on C. Burger, S. Pandit, and J. Weinmann (2015). ESMT innovation index 2014 – electricity supply
industry: The ‘big beyond’, ESMT Business Brief No. BB–15–01, (Figure 8).
‘[IF] STORAGE BECOMES AFFORDABLE ON
A LARGER SCALE, … CUSTOMERS MAY
DECIDE TO RELY COMPLETELY ON SELF-
PRODUCTION.’
TRANSFORMATION OF THE ELECTRICITY SECTOR
10 OXFORD ENERGY FORUM
The ‘Big Beyond’ not only questions the
grid-based business of utilities, but
utilities in their very existence. If
buildings become largely energyautonomous
via the IoT, all transactions
performed via blockchain, and ﬁnance
is undertaken via the sharing economy,
then utilities have to fear that they will
become the dinosaurs doomed for a
slow and painful decline of their
operations. By embracing the Big
Beyond, however, utilities might be able
to transform themselves into enablers
of a decentralized energy system. They
might even – rather than owning
large-scale assets, producing
electricity, and transmitting it to the
customer – build, own, or operate
decentralized energy generation
assets, steering them at the point of
consumption. It is only a matter of
technologies and mind set, since the
task – delivering energy to the
customer – would remain the same.
Renewable integration and the changing requirement of grid management
in the twenty-ﬁrst century
Rahmat Poudineh
Background
Since the dawn of the electricity
industry, uncertainly has always been
an inherent characteristic of the system.
The concept of uncertainty in the power
system has evolved over time, but
in the past it mainly implied demand
ﬂuctuation and components failure
(generation and network). Traditional
systems are equipped with a range of
control mechanisms to manage these
kinds of variability and uncertainty, in
order to provide a reliable service. In
such a paradigm, technologies are
mature and the behaviour of load
is fairly predictable. In recent years,
however, supply-side ﬂuctuations have
presented a new form of uncertainty
and added to the complexity of grid
management. The source of supplyside
variations is intermittency of
renewable resources, such as wind and
solar, whose penetration is accelerating
as environmental regulations tighten
around the world. For example, the
wind and solar PV installed capacity in
the EU region rose from 12.8 GW and
0.125 GW in 2000, to 128.7 GW and 88
GW respectively in 2014. This implies
that solar PV constituted 10 per cent
and wind represented almost 15 per
cent of total installed capacity in the
EU in 2014. The rapid penetration of
renewable resources imposes several
operational and economic challenges
on the electricity sector. The problem
of the system operator is no longer to
forecast load but net load, which is the
difference between the total load and
the supply from intermittent resources.
This increases the need for system
ﬂexibility; an ability that the power
system requires in order to utilize its
resources and deal with variations in
net load and generation outage over
various time horizons.
‘THE RAPID PENETRATION OF
RENEWABLE RESOURCES IMPOSES
SEVERAL OPERATIONAL AND
ECONOMIC CHALLENGES ON THE
ELECTRICITY SECTOR.’
Integration of wind and solar resources
necessitates system ﬂexibility in at least
three ways.
1 The stochastic nature of variable
generation leads to a wider
conﬁdence interval of net load
forecast; it increases the need for
additional ﬂexible resources. Although
variability declines with aggregation
and geographic dispersion, no
forecast measure is perfect and error
will exist even at an aggregated level.
Moreover, even with perfect
prediction, without curtailment, the
available ﬂexible resources may not
be sufﬁcient to meet the variation in
the net load.
2 The penetration of intermittent
resources can displace conventional
generation sources and this adversely
affects the amount of online ﬂexible
resources.
3 A lack of system ﬂexibility can result
in more frequent occurrences of
negative prices in wholesale markets;
this imposes additional costs on
renewable energy levies (where they
exist) to cover the difference between
contract and wholesale market prices
(when guaranteed payments are
linked to the wholesale energy price).
Additionally, even if all mechanisms
for managing variability of net load are
available, the current electricity markets
may not be positioned to incentivize
their efﬁcient use. Thus, I contend that
as intermittency increases and the
need for ﬂexibility becomes critical, the
system requires new models of grid
management both at operational and
institutional levels.
‘BY EMBRACING THE BIG BEYOND,
UTILITIES MIGHT BE ABLE TO TRANSFORM
THEMSELVES INTO ENABLERS OF A
DECENTRALIZED ENERGY SYSTEM.’
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11OXFORD ENERGY FORUM
Intermittency: a driver of change in grid
management
In this section I brieﬂy discuss some of
the operational and institutional (market
and regulation) changes in the power
system that result from the penetration
of intermittent resources.
Operational challenges
The operational challenges of
penetration of variable generation into
the power system depend on various
factors such as:
scale of intermittent resources,
correlation with demand,
ﬂexibility of the power system.
In order to illustrate some of these
challenges I use an example from
the California Independent System
Operator (CAISO) where the share
of renewables in the generation mix
has risen due to the ambitious goals
of the California Renewables Portfolio
Standard (33 per cent of electricity
from renewable sources by 2020 and
50 per cent by 2030). These targets
– along with environmental policies
and regulation regarding retiring or
mothballing of the power plants that
use coastal water – are expected to
change the energy landscape in favour
of renewables in California.
‘TRADITIONAL RELIABILITY METRICS
NEED TO BE SUPPLEMENTED BY VARIABLE
GENERATION INTEGRATION STUDIES.’
The increase of intermittency has
already started to manifest itself in
various operational challenges in
California’s electricity sector. The CAISO
power system is now experiencing short
and steep ramps, such that the system
operator needs to bring on or shut down
power plants more often and within very
short periods of time, in order to meet
the variations in net load. Furthermore,
during the hours of weak demand, the
CAISO system runs the risk of over
generation. This usually happens when
the system prepares for its morning or
evening ramp up, or during the night
times when supply from must-take
resources exceeds demand. These
effects have given rise to a new
phenomenon referred to as a ‘duck
curve’ because the shape of net load
resembles the body of a duck in which
the system is at the risk of over generation
at the lowest point of duck belly (see
chart. Additionally, when there are a lot
of renewables on line, and thus a limited
number of ﬂexible power plants, the
system has a limited frequency
response – a characteristic that is
crucial for the power system to recover
from faults (for example, sudden failure
of a massive power plant).
In order to operate reliably under these
conditions, new practices in planning
and operation need to be introduced.
Traditional reliability metrics need to be
supplemented by variable generation
integration studies. An example of such
new metrics is the Insufﬁcient Ramping
Resource Expectation (IRRE); this can
complement generation adequacy
metrics (Loss of Load Expectation
and other relevant indices) in order
to assess whether planned capacity
allows the system to respond to shortterm
changes in the net load. Such
operational changes pave the way
for the power systems of the future in
which:
resources react quickly and meet
expected operating levels for a
deﬁned period of time,
ramp directions can change rapidly,
energy can be stored or its use
modiﬁed,
power plants are able to start and
stop multiple times per day,
operators can make accurate
forecasts of their operating capability.
Flexibility services can be provided
by various resources such as: fast
ramping thermal generations (for
example, open cycle gas turbines),
storage, interconnection, demand
response, and even curtailment
of renewables. The adequacy of
transmission and distribution networks,
in terms of having no bottlenecks and
sufﬁcient capacity, is also crucial to
enable ﬂexibility.
Market and regulation
Such changes in traditional operation
and planning of the power system are
necessary but not sufﬁcient to enable
a ﬂexible power system. There is also a
need for institutional changes, in terms
of market (and product) design and
California Independent System Operator (CAISO) duck curve
Source: ‘What the duck curve tells us about managing a green grid’, California ISO Fast Facts.
TRANSFORMATION OF THE ELECTRICITY SECTOR
12 OXFORD ENERGY FORUM
regulation. These changes are required
to ensure not only that the current
resource owners have the incentive to
offer their ﬂexibility services, but also
that the market incentivizes new entrants
to meet the ﬂexibility requirements of
the system. Many of the conventional
generation sources have not been
designed to take on the ramping and
cycling duties that are now required,
and such operational modes increase
the of cost of their wear and tear and
fuel consumption. Therefore, a market
(or regulation) that values ﬂexibility is
required to enable these generators to
cover the costs of operating in a ﬂexible
mode when needed.
In the author’s view, there is a range of
measures that can be taken in order
to align electricity markets with the
requirements of a ﬂexible power system.
These include: modiﬁcation of the
current markets to make efﬁcient use of
available ﬂexible resources, designing
explicit incentives for ﬂexibility services,
and deﬁning tradable ﬂexibility products.
‘IN MANY POWER SYSTEMS WITH
FLEXIBILITY ISSUES, ELECTRICITY
MARKETS ARE NOT POSITIONED TO
MAKE EFFICIENT USE OF AVAILABLE
RESOURCES.’
In many power systems with ﬂexibility
issues, electricity markets are not
positioned to make efﬁcient use of
available resources. For example, in
some US regions where sub-hourly
markets do not exist, normal shortterm
variation of net load is met by
frequency regulation services – utilizing
the fastest, but most expensive, ﬂexible
resources. However, in other regions
(typically those with an ISO) such
variations are managed at a much
lower cost through procurement in
sub-hourly markets. The presence of
sub-hourly markets provides a unique
opportunity for the system operator to
exploit the inherent ﬂexibility of a large
ﬂeet of generation sources that can
alter their aggregate output rapidly.
The deﬁnition of standardized tradable
ﬂexibility products is also an important
part of the game. For instance, in
order to help the system and use
dispatchable ﬂexibility, the California
ISO is working on a proposal to
incorporate a new product, called
ﬂexible ramping products (FRP). FRPs
offer a ﬁve-minute ramping capability
that will be dispatched to meet ﬁveminute
to ﬁve-minute variations in net
system demand. In this context, the net
system demand is deﬁned as the load
plus export minus the schedules of
all resources that are not ﬁve minutedispatchable,
including renewables,
imports, and self-scheduled resources.
Another example in line with such
modiﬁcations in electricity markets
is the UK review of balancing
markets and changes to cash-out
arrangements, which aims to make
them reﬂect marginal rather than
average costs. Sharpening cash-out
prices provides incentives for the
market players to offer, invest in, or
secure ﬂexible resources to balance
their position at the time of system
stress. On top of that, the market for
ﬂexibility services can be regional
rather than national. This is speciﬁcally
relevant to the EU region, in which
short-term balancing markets can
become integrated where there is
sufﬁcient interconnection capacity
available (and will provide incentives
for investment in interconnections).
This promotes efﬁcient procurement
of ﬂexibility services because, with
the increase in the market size, more
options become available to national
system operators.
In addition to efﬁciency, another
objective of a ﬂexibility market is
to ensure the sufﬁciency of ﬂexible
resources. This requires explicit
incentives for adding ﬂexible resources,
since conventional capacity markets are
not a substitute for the ﬂexibility market.
This is simply because the standard
deﬁnition of resource adequacy does
not necessarily imply ﬂexibility: a
system can be adequate in terms of
resources available to meet seasonal
pattern of load proﬁle (capacity exceeds
demand with a margin at all time) but
lack the operational ﬂexibility to deal
with within-day ﬂuctuations of net load.
Furthermore, when capacity markets
do not explicitly value ﬂexibility, the
outcome of procurement favours lowcost
resources that lack the capability
to respond to short-term variation of net
load (the UK capacity market is a good
example for this). The bottom line is that
ﬂexibility is a component of scarcity;
thus a single-product capacity market
suffers from the very same ‘missing’
scarcity distortion that it was intended
to address in the ﬁrst place. Therefore,
the current capacity markets in the EU
region should be designed so that both
capacity and operational capability of
resources (and maybe also carbon
emission reduction) are valued.
‘…DEMAND RESPONSE IS A GOOD
EXAMPLE OF HOW REGULATION CAN
AFFECT THE FLEXIBILITY OF A POWER
SYSTEM.’
On the regulatory side, demand
response is a good example of how
regulation can affect the ﬂexibility
of a power system. For instance,
the rules regarding the nature of
demand response (equal treatment
of it with other resources and types of
markets in which demand response
can participate) are important for
utilization of this resource. In some
US regions, demand response is
allowed to participate in the ancillary
service markets; this is an attractive
arrangement for aggregators of
demand response services. Such
arrangements are also happening in
the UK, which is trying to integrate the
demand side in its balancing service;
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13OXFORD ENERGY FORUM
for example, under the Frequency
Control Demand Management (FCDM)
scheme, frequency response is
provided through automatic interruption
of contracted consumers when the
system frequency transgresses the low
frequency relay setting on site. The UK
National Grid is also trying to utilize
slower-responding demand response
for load following services under the
Short Term Operating Reserve (STOR).
Conclusions
The widespread deployment of
intermittent renewable generation in
several countries has led to an increase
in the relative and absolute magnitude
of power generation with random
output. This deployment constitutes
a major paradigm shift in grid
management, both at an operational
level and also in terms of market design
and regulation. In addition to traditional
resource adequacy metrics we need
new methodologies, in order to quantify
and assess the technically available
operational ﬂexibility of the power
system to be utilized for planning and
operation. Also, we need to ensure that
electricity markets and regulations not
only provide incentives for investment
in ﬂexible resources, but also make
efﬁcient use of available resources.
Market integration with energy-only markets and renewables: lessons of
experience from Australia
Rabindra Nepal and Tooraj Jamasb
The establishment of wholesale
electricity markets has been one
of the hallmarks of the marketoriented
electricity sector reforms
and restructuring process that started
in the early 1990s. The standard
model of liberalization included the
establishment of wholesale and retail
competition, vertical separation of the
distinct generation, network, and retail
activities, and incentive regulation of
electricity networks. A fuller physical
and ﬁnancial integration of the
separate national or regional electricity
markets was then required to enable a
deepening of competition. For example
in the EU, the process of creating a
common and integrated wholesale
market for electricity that started in
the second half of the 1990s, remains
a work in progress, while Australia
has, since 1998, focused on creating
an efﬁcient and integrated National
Electricity Market (NEM).
‘THE ESTABLISHMENT OF WHOLESALE
ELECTRICITY MARKETS HAS BEEN ONE
OF THE HALLMARKS OF THE MARKETORIENTED
ELECTRICITY SECTOR
REFORMS…’
This article draws upon the NEM’s
experience with market integration,
renewable energy, and network
regulation, and merges the ﬁndings
from recent studies: ‘Testing for
Market Integration in the Australian
National Electricity Market’, a paper
forthcoming in the Energy Journal
by Rabindra Nepal and John Foster;
‘Network Regulation and Regulatory
Institutional Reform: Revisiting the Case
of Australia’, an article in Energy Policy
from October 2014 by Rabindra Nepal
and Tooraj Jamasb; and ‘Electricity
Networks Privatization in Australia: An
Overview of the Debate’, an article in
Economic Analysis and Policy from
December 2015 by Rabindra Nepal
and John Foster.
We discuss the context within which
renewable energy development and
market integration can be implemented
as complementary policies in energyonly
markets, citing Australia as a
speciﬁc case, but drawing lessons
for the EU. The NEM provides an
interesting case study, since it is one
of the most transparent energy-only
wholesale electricity markets and it is
located in an island economy, while
it is also poised for greater uptake of
renewable energy. The lessons from the
NEM can be important for other regions
such as the EU, which is predominantly
an energy-only market moving towards
greater integration of renewables and
electricity markets.
The next section of the article provides
an overview of the structure and
organization of the NEM; following
this, the facts and underlying
reasoning behind the idea that the
development of renewable energy
and electricity market integration can
be complementary policy objectives
in Australia, are presented. We then
conclude by highlighting the broader
implications for other energy-only
markets, especially in the EU.
The National Electricity Market (NEM)
The NEM was established in 1998 in
response to the overall restructuring
of the Australian electricity sector. The
NEM is a gross pool arrangement for
wholesale electricity trade in Australia
and operates a deregulated market
in the physically interconnected, but
separate, regions of New South Wales
(NSW), Victoria (Vic), Queensland
(QLD), the Australian Capital Territory
(ACT), South Australia (SA), and
Tasmania (TAS). Tasmania joined the
NEM in 2005. Exchanges between
TRANSFORMATION OF THE ELECTRICITY SECTOR
14 OXFORD ENERGY FORUM
electricity generators and consumers
take place in a spot market through a
centrally coordinated dispatch where
the output bids from all generators
are aggregated and instantaneously
scheduled to meet demand. A dispatch
(or spot) price is determined every ﬁve
minutes and six dispatch prices are
averaged every half hour to determine
the spot price for each trading interval
in each of the regions of the NEM.
The dispatch price is the energyonly
price and does not contain any
components for capacity such as
‘capacity payments’. The National
Electricity Rules (the rules) set a
maximum spot price (market price cap)
of 13,100 AUD/MWh and a minimum
spot price (market ﬂoor price) of
–1000 AUD/MWh for the ﬁnancial year
2013/14. The market price cap prevents
wholesale spot prices from rising too
sharply during extreme peak loads or
at times of reduced baseload capacity.
The negative market ﬂoor price allows
generators to pay to stay online when
the cost of staying online is lower than
the cost of shutting down and re-starting
their plants. Hence, the minimum spot
price guarantees dispatch by bidding at
negative prices when a generator is too
costly to turn off.
‘THE GENERATION MIX IN THE NEM IS
DOMINATED BY LOW-COST BASELOAD
GENERATION.’
The generation mix in the NEM is
dominated by low-cost baseload
generation. Queensland, which has
installed capacity that amply exceeds
the region’s peak electricity demand,
is a net exporter in the NEM. Victoria
also beneﬁts signiﬁcantly from low-cost
baseload capacity, making it also a
net exporter of electricity. New South
Wales is a net importer of electricity
and has limited peaking capacity at
times of high demand. NSW mostly
relies on local baseload generation.
South Australia relies heavily on
electricity imports, although new
investment in wind power has reduced
its import dependency since 2005/06.
For example, the registered capacity
of wind and solar in SA in 2013 was 30
per cent of total capacity, while 2,987
MW of wind capacity will be added
(equivalent to 61 per cent of the total
generation mix) by 2023. Tasmania
is also a net importer of electricity,
although it became a net exporter
in 2011/12 for the ﬁrst time since its
interconnection with the NEM, due
to greater water availability and the
installation of new gas-ﬁred generation.
The Australian Energy Regulator (AER)
determines the maximum revenue
(revenue caps) that the transmission
and distribution companies can recover
from the network users in Queensland,
Australian Capital Territory, and
Tasmania. Likewise, the AER sets the
maximum network tariffs that distributors
can charge consumers (price caps)
in New South Wales, Victoria, and
South Australia. The transmission and
distribution networks remain stateowned
in Tasmania, New South Wales,
Queensland, and part of the Australian
Capital Territory. Victoria and South
Australia have fully privatized electricity
generation. Victoria corporatized and
privatized its electricity networks between
1995 and 1999 and both the transmission
and ﬁve distribution networks are now
in private ownership. South Australia
has privately owned transmission
networks, while the distribution network
is leased to private interests.
There are six operational
interconnectors among the ﬁve
electrically connected states in the
NEM. There are two interconnectors
operating between NSW and QLD, and
two between SA and VIC, while VIC–
TAS and NSW–VIC are each connected
by a single interconnector. There is
no direct interconnection between
QLD–SA and NSW–SA. The existing
interconnectors largely follow the state
boundaries, covering a distance of
more than 5000 kilometres, running
from Port Douglas in Queensland
to Port Lincoln in South Australia.
Hence, NEM is one of the longest
interconnected power systems in
the world. Geographical constraints
as an island economy have led
to the infeasibility of cross-border
interconnections, to date, in the NEM.
Market integration outcomes
Despite more than 14 years having
passed since the establishment of
the NEM, wholesale electricity price
differences persist across the Australian
states. Average daily prices are lowest
in VIC and QLD, while SA has the
highest average price, followed by TAS
and NSW. However, the average daily
wholesale price differences between
SA and VIC are the lowest among the
physically interconnected states. The
persistent differences in wholesale prices
can be attributed to the presence of
network constraints across the regional
interconnectors; this impedes the
wholesale market integration process
in the NEM. The Australian Productivity
Commission has expressed concerns
about under-investment in transmission
networks and in regional interconnectors.
In response, the AER has, in the past,
recognized the signiﬁcance of congestion
costs in the NEM and has allowed more
investments in the transmission network.
Network constraints occur due to physical
limits to the network’s transfer capability.
Network congestion can segment the
market and increase the wholesale
electricity price by displacing lowpriced
generation with more expensive
generation. Congestion can also lead
to market power in the segments of
the market. Finally, congestion also
promotes inefﬁcient electricity trade
ﬂows between the regions, as electricity
cannot be stored and ‘demand
and supply’ have to be balanced
in real time. The existing network
constraints, due to underinvestment in
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interconnectors, act as a barrier to the
wider, and much expected, development
of renewable resources, such as wind.
‘THE LACK OF ADEQUATE
INTERCONNECTION CAN PREVENT THE
DEVELOPMENT OF NEW WIND POWER
IN THE RESOURCE-RICH REGIONS’
Australia’s wind resources are mostly
concentrated in the regions with the
lowest electricity demand, these
include South Australia, Tasmania, and
Victoria. Queensland and New South
Wales exhibit high demand for electricity,
but have a low concentration of wind
resources. For example, South Australia
can reach a wind penetration (percentage
of average generation) of almost 70 per
cent, followed by Tasmania at 50 per
cent, while Queensland and New South
Wales have wind penetrations of around
1 per cent and 11 per cent, respectively.
The lack of adequate interconnection can
prevent the development of new wind
power in the resource-rich regions, and
lead to curtailment of existing capacity.
The costs in terms of lost revenue to
the wind power plants as a result of
curtailment are large, and hamper
the country in its attempts to meet its
national renewable energy targets.
Furthermore, wind projects are gradually
moving to less congested parts of the
networks across Queensland and New
South Wales, but these areas enjoy
lower quality wind resources, and
will eventually face higher costs. The
expansion of interconnectors, together
with increased export capacity from
low-demand regions (with high wind
potential) to high-demand regions, is
important in order to reap the security of
supply and sustainability beneﬁts from
wind generation in the NEM. Improving
market integration by increasing the
cross-border power ﬂow will also lead
to beneﬁts through efﬁciency gains,
both allocative and productive, as well
as through dynamic efﬁciency gains,
because a well interconnected market will
facilitate the optimization of investments
in both generation and transmission over
time across the NEM market.
Conclusions and policy implications
The most important factor for market
integration is to connect regional
electricity systems, physically and
adequately, through a transmission grid
and interconnectors. The transmission
capacity and prices will then determine
the volume of trade between the
different regions.
The EU is striving to create an
integrated electricity market in Europe,
while also aiming to signiﬁcantly
increase the share of its energy from
renewables. However, as the EU has
identiﬁed, the European transmission
and distribution networks need to be
adapted and extended to facilitate
power ﬂows from generation source to
end users across borders. Achieving
this objective will require substantial
investments. The island economies
with isolated electricity markets – in
Northern Ireland and the Republic of
Ireland – are also aiming to increase
integration with the continental
European electricity markets under the
EU ‘Target Electricity Model 2014’. In
addition, the Republic of Ireland has
a target to generate 40 per cent of its
electricity from renewables by 2020.
The NEM experience with market
integration suggests that harmonization
of regulatory and institutional
frameworks and electricity market
regulations can be coupled with private
ownership of assets, to improve market
integration across energy-only markets
poised for a large intake of renewables
in the wholesale trade. The case of
NEM suggests that a solid regulatory
framework could be a pre-requisite for
the necessary infrastructure investments
to take place in time for 2020. For
example, the AER recognized the
signiﬁcance of congestion costs across
the regional interconnectors and allowed
higher transmission investments in
regulatory decisions in 2009.
The regulatory test for transmission
expansion and network planning
in the NEM is based on identifying
investment options that maximize
the net economic beneﬁts. However,
the EU currently has 28 different
national regulatory frameworks. A
fragmented regulatory system based
on uncoordinated national policies can
become an obstacle to the formation of
an internal electricity market. Achieving
an integrated European market is
challenging, given the lack of adequate
interconnections, and inconsistency
in market design and rules among the
member countries, while aiming to
increase the share of renewable energy.
‘THE EU MEMBER STATES NEED TO
IMPROVE THE HARMONIZATION OF
THEIR REGULATIONS AND INCREASE
COOPERATION…’
The Australian experience reveals
that the large-scale development of
renewable energy and the integration
of regional electricity markets can be
complementary; these policies do not
necessarily conﬂict with each other
under adequate transmission capability
in energy-only markets. The EU can
improve the number and capacity of
interconnections in order to achieve
a more resilient energy-only market
and to implement the Energy Union
(currently uncertain due to inadequate
investments in electricity networks).
The regulatory framework for wholesale
markets and networks will be important
for facilitating trade across the
interconnectors; it will thereby improve
market integration among energy-only
markets with a high share of renewable
energy. The EU member states need
to improve the harmonization of their
regulations and increase cooperation,
in order to attract economically
beneﬁcial investments and achieve the
Energy Union.
TRANSFORMATION OF THE ELECTRICITY SECTOR
16 OXFORD ENERGY FORUM
Reforming European electricity markets for renewables
Richard Green and Goran Strbac
If the European Union is to meet its
2030 target and get 27 per cent of its
energy from renewable sources, it is
likely that roughly half of its electricity
will have to be from renewables. In
2013, renewable sources provided
27.7 per cent of electricity generation
in the EU-28, including 12.3 per cent
from hydro, 7.2 per cent from wind, and
2.6 per cent from solar power. A large
increase in solar and wind capacity
seems inevitable if the 2030 target is
to be met, but this will pose signiﬁcant
challenges for the electricity system.
More transmission capacity is planned,
but the existing infrastructure needs
to be used better, and that requires an
appropriate market design. We argue
here that more cross-border trading
will be needed – of energy in the long
term, and of balancing services (such
as reserve) in the short term – and
suggest changes that would facilitate
this. The cost of expanding Europe’s
renewable generation could be
signiﬁcantly reduced if coordination
across the EU replaced the present
patchwork of national approaches.
European integration and transmission
capacity
Europe’s underused transmission
capacity imposes signiﬁcant
opportunity costs on its people.
Transmission currently supports
energy arbitrage in day-ahead
scheduling, buying in currently cheap
markets and selling in more expensive
ones, but it could also support
capacity sharing and more efﬁcient
balancing in real time.
The beneﬁts of moving from the current
member state-centric market design
to one which is pan Europe-wide
have been quantiﬁed by modelling
at Imperial College, which provided
the basis of two 2013 reports to the
European Commission: one detailing
the beneﬁts of an integrated European
energy market, and the other giving
an impact assessment on a European
electricity balancing market. That
analysis demonstrated that the beneﬁts
of fully integrating EU energy and
capacity markets would be EUR12–40
billion/year and EUR7–10 billion/year
respectively by 2030, while integration
of the EU balancing market would
save an additional EUR3–5 billion/
year. These savings go far beyond the
EUR2.5–4 billion/year that the EU has
saved through its existing measures to
integrate its electricity markets through
day-ahead energy arbitrage. The
potential gains would be even greater
if transmission capacity was used to
support a more rational deployment of
renewable generation.
Comparative advantage – signiﬁcance of
transmission
The policies of most EU governments
have had the effect of spreading wind
and solar power across the continent,
making support available to a wide
range of renewable generators. The
UK government set feed-in tariffs at
levels that encouraged the installation
of 8.3 GW of solar PV capacity (to
October 2015), even in the cloudy,
northerly British Isles, while the German
government has supported 34.7 GW
of wind capacity, even with a 19 per
cent average load factor that is only
two-thirds of the average for the UK
and Ireland. In other words, national
policies have ignored the principle of
comparative advantage.
In a paper forthcoming in The Energy
Journal, working with Iain Staffell and
Danny Pudjianto, we have calculated
the beneﬁts and costs of a more
rational deployment of renewable
capacity, one that would site a higher
proportion of generation in areas
where it will have high load factors. We
ﬁnd that by moving wind generation
towards the windier areas of north-west
Europe, it would be possible to get the
same level of output from 15 per cent
less capacity. Concentrating solar PV
generation towards the south would
save 8 per cent of installed capacity.
Overall, this would save EUR19 billion
a year in interest and depreciation
costs. However, power ﬂows across the
continent would increase signiﬁcantly,
since a concentrated portfolio of
renewable generators would produce
stronger peaks and troughs in output
than a dispersed one. Our modelling
suggests that an additional EUR4
billion a year would be needed to
ﬁnance additional transmission lines
and peaking generation, for times when
the local renewable output was low and
even the new lines were congested.
The net gain is therefore considerable,
but there are signiﬁcant challenges to
overcome before such a coordinated
deployment could be possible.
European energy market design
Many of these challenges are in
the areas covered by the European
Commission’s July 2015 consultation
on a new energy market design.
Electricity markets in Europe largely
follow a common pattern; much trading
is bilateral and concluded some time
in advance, so that both generators
and retailers can ﬁx a price for most of
their sales and purchases. There is a
voluntary day-ahead auction run by an
independent power exchange, which
‘…THE EXISTING INFRASTRUCTURE
NEEDS TO BE USED BETTER, AND THAT
REQUIRES AN APPROPRIATE MARKET
DESIGN.’
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17OXFORD ENERGY FORUM
may cover one country or a small group
of neighbouring countries. Adjustments
close to the time of delivery are made
by the local transmission system
operator, trading bilaterally with
generators and a few consumers (or
their aggregators) able to offer demand
reductions at short notice.
‘ENCOURAGED BY THE EUROPEAN
COMMISSION, MARKET COUPLING HAS
GRADUALLY SPREAD ACROSS NORTHWEST
EUROPE…’
One spot market, Nord Pool, has
been multinational since 1996, and
uses a market splitting algorithm to
set different prices on either side of a
zonal or national border if transmission
capacity is less than that required for
the ﬂows that would equalize prices.
France, Belgium, and the Netherlands
started market coupling in 2006, taking
account of exports and imports in
their national auctions, and setting
their level to equalize prices across
borders if possible, and exhaust the
available transmission capacity if
not. Encouraged by the European
Commission, market coupling has
gradually spread across north-west
Europe, so that 19 countries had
coupled their day-ahead markets
by February 2015. If there is enough
transmission capacity, an area from
Portugal to Great Britain, to Norway,
Finland, and the Baltic States, and from
Germany via Austria and Slovenia to
Italy could have a single day-ahead
price.
Although day-ahead markets may be
the most visible sign of a liberalized
electricity industry, most electricity
trading actually takes place on a
longer timescale, while secure system
operation depends on very short-term
decisions. Long-term contracts allow
generators and retailers to ﬁx a price
for most of their expected output
and purchases, giving them ﬁnancial
security, even though the day-ahead
markets allow them to adjust their
positions to reﬂect actual patterns of
demand and plant availability. This
ability to adjust positions is increasingly
important as the share of intermittent
renewables rises, since their outputs
cannot be accurately predicted on the
timescale of long-term trading.
If Europe is to concentrate its renewable
generators in areas of comparative
advantage, however, long-term sales
contracts will certainly be required: the
consumers supporting (still relatively
expensive) generators abroad will want
to know that they are getting some power
in return for their support. This requires
a mechanism for delivery, and long-term
access to capacity on cross-border
interconnectors has been made available
through auctions for many years. There
are two problems relating to the use of
contracts for physical capacity.
1 In the past, there were fears that a
contract holder might withhold
capacity from the market in order to
widen price differentials between the
two ends of the interconnector. This
problem can be resolved with a ‘use it
or lose it’ rule that returns any unused
capacity to the market if the contract
holder has not scheduled the ﬂows to
which they are entitled.
2 The second problem, more
fundamental, is that physical contracts
do not reﬂect the physics of the grid.
Power ﬂows can be netted off each
other. If 2 GW is sold from France to
the UK, this would appear to use the
full capacity of the cross-Channel link,
but if a second deal sends 1 GW in
the opposite direction, a third trade
becomes possible, giving a gross
contracted ﬂow from France to the UK
of 3 GW. It is highly unlikely that we
could ﬁnd a watertight way to issue
physical contracts for 3 GW of power
to ﬂow over a 2 GW interconnector,
because the third GW depends on a
counter ﬂow that might not happen in
practice.
Financial transmission rights (FTRs)
do not have the same restrictions as
physical contracts. They offer price
insurance for a cross-border trade
by paying the buyer the difference
in prices between two points on
the system. As a purely ﬁnancial
contract, there is in principle no limit
to the number of FTRs that could be
bought and sold. In practice, there
is a natural hedge for each FTR, and
that is the revenue received by the
owners of an interconnector when
power ﬂows across it from a lower- to a
higher-price area. The capacity of the
transmission system determines the
net volume of FTRs that can receive
this natural hedge – at most 2 GW in
either direction in the case of the line
mentioned above. However, a net
volume of 2 GW is consistent with
2 GW of contracts in one direction, or
3 GW in one direction and 1 GW in the
other, and so on. If the holders of 3
GW of FTRs from France to England
are receiving a payment because
the power price is higher in England,
then the holders of the FTRs from
England to France are making the
same payment (per MW). The net result
is that the transmission companies
make the payment for 2 GW of FTRs,
just matching the capacity that
they would normally have available.
Absent bankruptcy, the holders of the
England–France FTRs are guaranteed
to provide a ﬁnancial counter ﬂow
in a way that cannot be ensured for
physical contracts.
Creating long-term FTRs might also be
a way of ﬁnancing the extra investment
in transmission assets that will be
needed to accommodate the more
volatile power ﬂows as renewable
capacity rises. Companies expecting
to trade power over long distances
will pay the companies developing
transmission assets for the FTRs that
the traders need to lock in prices; the
combination of the FTR payments and
the price differences that they hedge
TRANSFORMATION OF THE ELECTRICITY SECTOR
18 OXFORD ENERGY FORUM
gives the transmission owners a more
stable revenue stream, independent of
day-to-day ﬂuctuations in fuel prices or
renewable outputs.
FTRs would help create a single electricity
market that operates on long timescales
but the short-term markets that are crucial
for the secure delivery of power remain
largely national. While system operators
rely solely on plants and consumers
within their own borders to provide
balancing services, they are likely to miss
alternatives that offer better value. In the
early days of the New Electricity Trading
Arrangements in England and Wales in
2001, the system operator had to set
high imbalance prices because of the
cost of buying power from a relatively
small number of ﬂexible generators inside
the market. As soon as the operator
realized that ﬂows from France and
Scotland could be adjusted by similar
amounts within the required timescales,
the presence of a much cheaper option
helped prices to fall dramatically.
Balancing mechanisms that allow
cross-border participation require
the effective exchange of information
on short timescales. They also need
transmission capacity to be available,
and we do not currently have a
mechanism that allows for this. If crossborder
capacity is entirely allocated
at the day-ahead stage, there will be
none available for the country importing
energy to also import balancing
services from its neighbour.
Case for Transmission System Operators
North American power markets jointly
optimize energy and reserve decisions,
for they have learned that separate
optimization increases costs for
consumers. Since the markets are run
by Independent (transmission) System
Operators, they take the constraints on
the transmission system into account
when they do this.
Transmission capacity in Europe is
currently allocated by power exchanges
trading energy, while separate
institutions deal with reserve and
balancing. That implies that all the
transmission capacity is allocated to
energy arbitrage, which is unlikely to
be the optimal outcome. The European
Commission sought views on whether
cross-border Transmission System
Operators should be encouraged:
promoting more efﬁcient balancing
is one area in which they would
have an advantage over the current
arrangements. In principle, and already
sometimes in practice, the operator
in one country can acquire balancing
services from its neighbour, but the
extra stages of decision making and
communication involved are likely to
reduce the beneﬁts of doing so.
It is a sign of progress that the
European Commission thinks the
establishment of cross-border
Transmission System Operators is
worth consulting on: in the past,
national electricity markets were
ﬁercely separate. National renewable
energy policies are still uncoordinated,
and concentrating renewables in
more favourable locations would
bring important savings. Even with
the current capacity mix, the gains
from greater trade have become
apparent, and will increase as the
share of wind and solar generation
continues to rise. The existing linkages
between day-ahead markets need
to be supplemented with greater
coordination on longer and shorter
timescales. Cross-border trading of
long-term contracts for energy would
be facilitated by the use of Financial
Transmission Rights that hedge price
differences between areas, while
respecting the laws of physics in a way
that past commercial arrangements for
long-distance power ﬂows have not.
Short-term balancing costs could be
reduced if system operators sometimes
bought balancing services and reserve
from their neighbours. To integrate
balancing between countries, however,
we may have to integrate energy and
reserve markets inside each country.
American experience shows that
this can be done, but the political
challenges in creating a good market
design should not be underestimated.
Supporting renewable generation in the UK
David M. Newbery
Introduction
The European Commission’s proposed
Energy Union Package (introduced in
the document subtitled ‘A Framework
Strategy for a Resilient Energy Union
with a Forward-Looking Climate
Change Policy’ dated 25 February
2015) proposes integrating electricity
from renewable energy sources
(RES-E) into the market. It aims to
move away from the unresponsive
standard feed-in tariffs (FiTs), replacing
them by Premium FiTs (PFiTs), which
pay a premium on the market price but
require generators to take responsibility
for selling and balancing their power.
This article examines the logic,
‘…CONCENTRATING RENEWABLES IN
MORE FAVOURABLE LOCATIONS WOULD
BRING IMPORTANT SAVINGS.’
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19OXFORD ENERGY FORUM
drawbacks, and possible resolutions of
this proposal for future UK renewables
support.
History of UK renewables support
Britain has tried almost every form
of renewables support since the ﬁrst
Non-Fossil Fuel Obligation auctions
in the 1990s and so is a useful
testbed for the efﬁcacy of differing
forms of renewables support. As
the name suggests, the ﬁrst form
of support was a series of auctions
for the prices to be paid for various
categories of non-fossil fuel (which
was extended to other non-fossil fuels
from nuclear power under pressure
from DG COMP). The early auctions
demonstrated their competitive effect
by driving down costs (or the auction
prices), but either the winner’s curse,
or the lack of any penalty for multiple
bids between which the winner could
choose in light of subsequent planning
application success, led to a fall in the
rate at which auction winners delivered
commissioned plant. Inﬂexibilities in
project deﬁnition (size, exact location)
also meant that small changes
rendered the initial contract invalid.
‘BRITAIN HAS TRIED ALMOST EVERY
FORM OF RENEWABLES SUPPORT
SINCE THE FIRST NON-FOSSIL FUEL
OBLIGATION AUCTIONS IN THE 1990S…’
These objections could surely have
been overcome, but a change in
Government in 1997 from Conservative
to Labour resulted in a reconsideration,
and with it the Utilities Act 2000 that
placed an obligation on electricity
supply companies to source a
speciﬁed share of their sales from
renewable generation, or pay a pre-set
penalty for any shortfall. Companies
producing RES-E were awarded
a speciﬁed number of Renewable
Obligation Certiﬁcates (ROCs) for
each MWh they produced; however,
they were responsible for selling
the electricity and dealing with any
imbalances, in contrast to the less
risky FiT schemes which required the
System Operator to handle all off-take,
and under which the developer was
paid a set price for metered output. The
value of ROCs is determined by supply
and demand and the penalty price for
not delivering sufﬁcient ROCs to meet
the targets.
One obvious advantage that quantitybased
instruments like ROCs enjoy
is that the volume of RES-E to be
supported can be limited, and hence
the impact on the budget is also
predictable and controllable. In the
case of ROCs, the volume required to
be bought by the utilities is set each
year, usually with some ‘headroom’
that is an estimated uplift on the
predicted capacity during the year.
The excess demand from retailers’
penalty payments produces additional
revenue that is returned to increase
the value of the ROCs. By reducing
the headroom, or if developers are
unusually successful and exceed the
predicted amount, the market price for
ROCs will fall and discourage further
expansion. In contrast, a ﬁxed FiT with
no cap on the number that can be
issued risks excessive demand and
excessive budgetary cost. While wind
developments take years to proceed
from the initial idea through planning
to grid connection agreements and
construction, and hence can be
predicted well in advance, solar PV
panels can be ordered and installed
within weeks. Spain and Italy (and the
UK) have demonstrated that if the FiT
is set too high compared to the rapidly
falling cost of PV, installation rates
can accelerate and create such ﬁscal
pressures that the support system can
collapse.
One other important advantage that
ROCs or PFiTs have is that they can
give better locational signals than the
classic FiT, which normally pays the
same amount regardless of location.
In the UK, wind developers have to
pay locational Transmission Network
Use of System charges, which vary
very signiﬁcantly across the country.
If electricity were locationally spot
priced, as in many parts of the USA,
the temporal and spatial signals
would provide additional efﬁcient
location signals, with the premium
payment remaining as a support to
the high capital cost. The limitation to
these locational signals is that if the
same premium is given regardless of
location, the beneﬁt of generating in a
high wind area with a higher capacity
factor will be unnecessarily ampliﬁed,
distorting location decisions to such
locations and providing excess rent to
the developers there.
‘… THE IDEAL FORM OF SUPPORT
WOULD TARGET THE CAPITAL COST,
NOT THE OPERATING COSTS.’
As the aim of the support is to
encourage deployment of high capital
cost plant to drive down future costs,
the ideal form of support would target
the capital cost, not the operating
costs. Germany has a very simple
solution which largely achieves this by
paying support for a speciﬁed number
of MWh/MW capacity, so windier areas
receive only slightly more support than
less windy areas (by receiving it more
quickly). This has the advantage of
reducing excessive rent to high wind
areas, and effectively treating the
electricity produced as of equivalent
value to any other electricity – correctly,
as the electrons are not coloured grey
or green depending on source.
The downside to the beneﬁt of
controlling the quantity and hence the
ﬁscal cost of support is that developers
ﬁnd it hard to predict their future
revenue. With ROCs there is a double
uncertainty: the future value of ROCs
and also the future price of electricity.
Further, the price of electricity in the
TRANSFORMATION OF THE ELECTRICITY SECTOR
20 OXFORD ENERGY FORUM
UK is set by either coal or gas (and the
price of carbon), as fossil plant remains
at the margin for all but a few hours per
year. As a result fossil plant enjoys a
natural hedge while low-carbon plant
with low variable costs is fully exposed
to the very volatile wholesale price.
The result of the higher risk facing
RES-E developers in the UK has
been a slower uptake than might be
expected, given that the UK has far
better wind resources than Germany.
In 2004 the UK generated about 8
per cent of the amount that Germany
generated from wind, but by 2011 the
proportion had risen to more than 30
per cent, reﬂecting the UK’s higher rate
of growth as it started from a very low
base (ﬁgures taken from the Eurostat
website).
In response to concerns about the high
cost of supporting RES-E, combined
with its lagging performance, as well
as growing concerns over security of
supply, the UK Government passed
the Energy Act 2013, which launched
the Electricity Market Reform (EMR).
EMR was intended to meet the EU RES
and climate change targets at lower
cost while maintaining reliability. In
contrast to the Energy Union Package,
it aims to replace PFiTs with Contractsfor-Differences
(CfDs) for RES-E,
closer to the classic FiT, as the way
to lower the cost of RES-E support.
The Department for Energy & Climate
Change (DECC) initially set the strike
prices for these CfDs on the basis of an
assumed hurdle rate, which the Panel
of Technical Experts, commenting in a
2013 report on the delivery of the EMR,
criticized as being too high. Instead,
the Panel suggested that auctions
were a better way of eliciting the price
at which developers would be willing
to invest, and under pressure from
DG-COMP again, DECC announced
an auction for RES-E CfDs on 1
September 2014. The results of that
auction are given in Table 1.
It is clear that the auction prices
are considerably less than the
administratively set strike prices and it
is simple to estimate the reduction in
the implied hurdle rate by comparing
the administered strike price with the
auction price. Given the auction prices,
the administered strike prices, and
assumptions about the cost of wind
turbines, their capacity factors, and
operating costs it is straightforward
to compute the difference in the
internal rates of return between the
two alternative income streams.
The differences are large at 2.2–3.4
per cent real (depending on these
parameters and whether any credit is
given for post-contract operation at the
unsubsidized price).
The Energy Union Package
Just after the UK’s ﬁrst CfD auction
in February 2015, the Energy Union
Package was launched, stating that:
… renewable production needs
to be supported through marketbased
schemes that address
market failures, ensure costeffectiveness
and avoid
overcompensation or distortion.
Low-cost ﬁnancing for capital
intensive renewables depends
on having a stable investment
framework that reduces
regulatory risk.’ (Energy Union
Package, 2015).
This Commission proposal appears to
pay more attention to the advantages
of PFiTs mentioned above than to their
impact on risk and ﬁnancing costs,
and would seem to reverse the logic,
painfully learned in the UK, of moving
from PFiTs to FiTs with their revenue
guarantee and hence reduced risk and
cost. German, Danish, Spanish, and
Italian case studies (reported in two
articles in the journal Energy Policy:
‘Environmental policies and risk ﬁnance
CfD auction allocation: round 1
Technology
Admin
price
Lowest
clearing
price 2015/16 2016/17 2017/18 2018/19
Total
capacity
(MW)
Advanced conversion
technologies
GBP/MWh 140 114.39 119.89 114.39
MW 36 26 62
Energy from waste with
combined heat and power
GBP/MWh 80 80 80.00
MW 94.75 94.75
Offshore wind GBP/MWh 140 114.39 119.89 114.39
MW 714 448 1162
Onshore wind GBP/MWh 95 79.23 79.23 79.99 82.50
MW 45 77.5 626.05 748.55
Solar PV GBP/MWh 120 50.00 50.00 79.23
MW 32.88 36.67 69.55
Note: the GBP50 bid for solar PV in 2015/16 was withdrawn.
Source: DECC ‘Contracts for Difference (CfD) Allocation Round One Outcome’, 26 February 2015.
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21OXFORD ENERGY FORUM
in the green sector: Cross-country
evidence’ by Chiara Criscuolo and
Carlo Menon, 2015, and ‘Lessons for
effective renewable electricity policy
from Denmark, Germany and the
United Kingdom’ by Judith Lipp, 2007,
and also in the EPRG Working Paper
1603 ‘Energy subsidies at times of
economic crisis: a comparative study
of Italy and Spain’ by Arjun Mahalingam
and David Reiner) demonstrate that
a well-designed FiT can be cost
effective (with suitable degression
tracking falling costs), can deliver rapid
deployment, and encourage the cost
reductions that are the logic behind the
European Commission’s Renewable
Energy Directive.
‘THERE ARE GROWING CONCERNS …
THAT THE UNANTICIPATED MASSIVE
INCREASE IN RES-E PRODUCTION IS
LOWERING WHOLESALE ELECTRICITY
PRICES…’
However, there are growing concerns
from electricity generating companies
that the unanticipated massive increase
in RES-E production is lowering
wholesale electricity prices, particularly
in Germany, which has massive wind
and solar PV penetration (see, for
example, ‘The impact of wind power
generation on the electricity price in
Germany’ by Janina Ketterer in the
journal Energy Economics, 2014). There
is concern that excessive generation at
some particular time and place would
normally lower prices and discourage
further investment there, but a ﬁxed
FiT would remove that feedback. On
the other hand, a PFiT that just pays a
(normally ﬁxed) premium on the local
spot price would provide the necessary
feedback.
The practical question is how to
combine the advantages of a PFiT
with the risk-reducing properties of a
FiT or CfD. The logic of the Renewable
Energy Directive is that it solves the
‘club good’ problem of ﬁnancing
deployment to reap the dynamic
economies of scale (learning-bydoing),
which is primarily more about
the design, location, and installation
of the RES-E plant, and less about its
operation (which, if it is mature enough
to warrant mass deployment, should
primarily depend on the resource:
wind or sun). This would suggest
rewarding RES-E for availability rather
than output, or per MW rather than
per MWh, making renewables just like
capacity in a capacity auction (of the
kind successfully implemented as part
of the EMR), as the aim would be to
identify the ‘missing money’ needed
to justify deployment, while providing
a long-term contract for availability
that addresses the ‘missing (futures)
market’ problem. See the forthcoming
article by David Newbery ‘Missing
Money and Missing Markets: Reliability,
Capacity Auctions and Interconnectors’
in Energy Policy.) To reduce risk further,
balancing and other ancillary services
could be procured competitively by
the System Operator, while the RES-E
developer could be offered a costreﬂective
contract whose cost would be
factored into the auction for capacity
availability. Other aggregators or supply
companies could offer power purchase
agreements (PPAs) for the metered
output, based on a prediction of the
local wholesale price, further reducing
transaction costs and risks.
Conclusion
The intention behind the Energy
Union Package – of making RES-E
face more efﬁcient price signals – is
sound but needs to be reconciled
with a sufﬁciently stable investment
climate that allocates risk to those
best placed to bear it, while providing
adequate incentives for efﬁciency. This
article argues that capacity contracts
with suitable PPAs and contracts for
ancillary and balancing services (with
all contracts reﬂecting efﬁcient market
value) are the logical solution and
should support the delivery of lowcarbon
electricity at least cost.
Centralized or decentralized? Remove ﬁrst the regulatory barriers
Ignacio Pérez-Arriaga and Scott Burger
Regulation matters
Electric power systems are currently
facing signiﬁcant changes as a result
of the deployment of information and
communication technologies (ICTs),
advanced power electronics, and
distributed energy resources (such as
gas-ﬁred distributed generation, solar
PV, small- and medium-sized wind
farms, electric vehicles, energy storage,
and demand-side management).
These distributed energy resources
(DERs), unlike ‘traditional’ centralized
generating units, are characterized by
their small capacities (several kilowatts
to several megawatts), their diverse
nature (generation, storage, responsive
demand, or any combination thereof),
and their connection to low and
medium voltage electricity distribution
grids. DERs, if properly integrated, may
have the potential to deliver not only
the valuable electricity services that are
traditionally provided by centralized
TRANSFORMATION OF THE ELECTRICITY SECTOR
22 OXFORD ENERGY FORUM
generating units, but also new services
that are enabled by their distributed
nature.
‘WHILE DERS ARE CERTAINLY GAINING
TRACTION IN POWER SYSTEMS, THE
DEGREE TO WHICH THEY WILL PROVE
INFLUENTIAL REMAINS AS DIFFICULT TO
PREDICT AS EVER.’
Bold claims have been made – by the
CEOs of some of the most important
electric utilities in the world, by
regulatory authorities like those from
the state of New York or the UK, by
the European Commission, by the
most important associations of the
power industry, and by energy think
tanks – announcing the future, even
imminent, disruptiveness of DERs in
the provision of electricity services.
Our research group at MIT – currently
working on the ‘Utility of the Future
Study’, in collaboration with the Institute
for Research in Technology (IIT) at
Comillas University in Madrid (details
available on the website of the MIT
Energy Initiative) – has surveyed over
200 different kinds of recently created
business models that employ DERs
in some way. Something is certainly
going on, but, while DERs are certainly
gaining traction in power systems,
the degree to which they will prove
inﬂuential remains as difﬁcult to predict
as ever.
From a strict economic viewpoint,
the answer to the question of whether
the future provision of electricity
services will be predominately
centralized or decentralized, and in
what likely proportion, will depend on
the characteristics of the services to
be provided and the cost and
performance of the diverse means of
supplying them. Other factors – such
as customer preferences driven by
cultural background, environmental
concerns, fashion, satisfaction with
or animosity towards the incumbent
utility, social pressure, and the impact
of neutral or biased information – will
also have a signiﬁcant inﬂuence on the
outcome.
This paper argues that regulation of
the power sector, as the materialization
of national or supranational energy
policy, either correctly designed or
ﬂawed, is perhaps the most important
factor presently inﬂuencing the
level of penetration of DERs in the
short to medium term. The present
regulation is woefully inadequate to
meet the incoming challenges; an
in-depth review and corresponding
modiﬁcation is essential to create an
economically neutral playing ﬁeld,
enabling centralized and decentralized
resources to compete and collaborate
efﬁciently, while recognizing that they
perform under very different conditions,
in terms of size, technology, or
location in the network, among other
characteristics. This is an urgent task,
since so much is at stake. The irruption
of DERs has added pressure to the
need for regulatory changes to be
introduced (changes that should have
been made some time ago).
This paper makes the case that going
back to applying the fundamentals of
microeconomics to power systems,
is the best way of adding value to the
current debate about decentralization
and evolution in the provision of
electricity services. This requires:
1 Reconsidering the deﬁnition of
‘essential electricity services’;
2 Examining how to compute the
prices and regulated charges that
should apply to every agent in the
system so that economic efﬁciency
(optimization of social welfare) is
maximized; and
3 Understanding what, if any, is the
value that aggregation of DERs
and any associated business
models may bring to the entire power
system.
Essential electricity services and their
prices and charges
Regardless of the regulatory
framework, only a small number of
mutually exclusive and collectively
exhaustive electricity services are
needed for the correct (efﬁcient,
reliable, and environmentally sound)
functioning of a power system: energy
(kWh), ﬁrm capacity (kW), operating
reserves at several time response
levels, network capacity (kW), voltage
support, and management of
constraints and losses. We term
these essential services ‘primary
services’.
Some of these essential services, like
operating reserves, may exhibit slightly
different deﬁnitions under different
conditions; however, the basic
concept does not change. Perhaps in
the future, the physical evolution of the
power sector and its organization will
require the addition of novel primary
services to our list; however, we
postulate that the set described
herein is exhaustive given today’s
paradigm, and that any potential future
additions will adhere to the same
philosophy that we describe.
A comprehensive system of economic
signals is needed to allow the
anticipated large diversity of agents
to compete and to collaborate in the
efﬁcient provision of these services,
while maintaining the reliability of the
power system. These economic signals
are prices (for those services provided
in competition via markets) and
regulated charges (for the regulated
monopolistic activities); furthermore,
these signals act as the power sector’s
nervous system, efﬁciently and
effectively communicating, to all the
providers and consumers of electricity
services, the prices and charges that
correspond to the particular services
provided in their speciﬁc situation in
time and space.
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23OXFORD ENERGY FORUM
Prices
Strict application of microeconomics
to the joint mathematical formulation
of power system operation and
planning results in prices that are the
dual variables – also called shadow
prices – of the constraints in the
problem, with the commodities of the
corresponding electricity services being
the magnitudes on the right hand side
of these constraints. In simpler words,
the price is equal to the additional
system operation cost of tightening the
constraint by one unit. For instance,
the constraint requiring the balance
of demand and generation, at each
network node and at any time, results in
a speciﬁc energy price at each moment
in time at each node: the energy nodal
price or ‘locational marginal price’
(LMP). Other constraints emerge
due to the system operator’s desire
to guarantee that certain essential
services (such as primary, secondary,
and tertiary reserves, or ﬁrm capacity
targets, perhaps with some minimum
ﬂexibility requirements) are provided
in prescribed quantities. There are
also prices for relieving voltage- and
congestion-related network
constraints.
‘… THE PRICE IS EQUAL TO THE
ADDITIONAL SYSTEM OPERATION COST
OF TIGHTENING THE CONSTRAINT BY
ONE UNIT.’
Regulators may want to impose
additional constraints – such as
emissions or renewables targets, fuel
quotas, or banned technologies – all
of which result in additional services
and their associated prices and
charges. Secondary services can be
derived from the essential ones, such
as ﬁnancial products based on the
prices of energy or network
congestion.
LMPs are just energy prices, but they
are a reﬂection of the diverse costs
of production and demand response
everywhere, as well as of the impacts
of network losses and technical
constraints. Ideally nodal prices
should reach every customer, and
even every appliance, but practical
reasons may advise differently.
Deciding the optimal granularity – in
other words, how far to go with
spatial and time differentiation – of all
relevant prices and charges is a major
design issue for the power sector of
the future. This is strongly related to the
value of aggregation that is discussed
later.
Charges
Network charges
Regulated network charges are
necessary to recover and to allocate
properly the total network costs.
Given the physical and economic
characteristics of actual networks,
this is not possible with just the
differences between LMPs.
Distribution utilities have to apply
network use of system (DNUoS)
charges to recover the total costs
of investment, operation, and
maintenance. DNUoS charges can
also signal to network users how their
utilization patterns impact network
costs.
Regulators are faced with the double
challenge of: a) recovering network
costs and b) sending efﬁcient
economic signals to the network
users. These signals must enable a
level playing ﬁeld between electricity
service business models connected
everywhere in the network to exist.
Furthermore, the implementation
of network charges must not
unnecessarily distort energy prices.
The customary design of DNUoS
charges, meant for pure consuming
agents in power systems where DERs
are considered a minor exception,
does not hold anymore. It should be
urgently ﬁxed, before more substantial
distortions occur. The new design
should conform to these criteria:
Ignore what happens beyond the
meter; network charges should only
be based on the network location
and the individual proﬁles of net
power injection or withdrawal.
Assume a well-established
procedure exists that designs an
efﬁcient or ‘well-adapted’ network for
an estimated future pattern of
injections and withdrawals; this
procedure should allow the
identiﬁcation of the underlying cost
drivers, such as Connection (the
network that is needed to provide a
‘basic or minimum’ level of electricity
service to all network users),
Capacity (the additional network that
is needed to meet the expected most
demanding conditions of injections
and/or withdrawals), and Reliability
(the extra network necessary to
satisfy some required quality of
service standard for all operating
conditions).
The individual network charges will
be determined following a common
method that determines the
contribution of each individual
utilization proﬁle, at any given
location, to each cost driver. The
costs of any network capacity that is
not directly required by the cost
drivers should be socialized.
Socialization of network costs is a
common practice today, but a sound
justiﬁcation is needed.
The network charges will be the
amounts of money (per month, for
example) associated with each cost
driver and this is how they should be
presented in the electricity bills.
Traditional tariffs (USD/kWh, USD/kW,
USD/customer) should be
abandoned, since they are
inadequate to represent the diversity
of behaviours of network users (what
kWh? what kW?).
TRANSFORMATION OF THE ELECTRICITY SECTOR
24 OXFORD ENERGY FORUM
Policy charges
In addition to network charges,
in most power systems there is a
diversity of other costs that have been
traditionally recovered from electricity
consumers (such as: subsidies to
domestic fuels, clean technologies or
social tariffs; charges for efﬁciency,
energy conservation or innovation
programmes; competition transition
charges, etc.)
‘IN SOME COUNTRIES… THESE
ADDITIONAL REGULATED COSTS MAY
BE COMPARABLE TO THE AMOUNT OF
NETWORK COSTS.’
In some countries the total magnitude
of these additional regulated costs
may be comparable to the amount of
network costs. Therefore the method of
allocation should not be taken lightly.
Cost causality is weak or inexistent for
these costs, so it has to be decided
in the ﬁrst place whether electricity
consumers should shoulder them or
not. Flawed allocation approaches
may encourage grid defection. It may
be advisable to include most of these
costs in a general taxation system,
unrelated to electricity rates.
Consumers should not be able to
avoid them, as they are unrelated
to consumer or producer behaviour.
However, this avoidance is possible if
policy charges are allocated using the
same criteria as for network charges.
This is the case of ‘net metering’, which
is discussed later.
The value of aggregation
One can argue that, conceptually,
under a well-designed system of prices
and charges, it should be immaterial if
DERs or any other agents, centralized
or decentralized, are or are not
aggregated. What is, then, the value of
aggregation, and how does it depend
on regulation?
Aggregation is the grouping of distinct
agents in a power system to act as a
single entity when engaging in power
system markets (both wholesale and
retail) or when complying with power
systems regulations. Aggregators may
act as intermediaries between the
complexity of the power system, with
multiple electricity services and a price
or charge for each one of them, and
the simpler signals that each agent is
capable of handling at a given instant
in time.
Identifying the value of aggregation is
relevant, in order to determine whether
this activity should be facilitated, or
even encouraged, or, on the contrary
be left to the initiative of the agents.
Aggregation has many points in
common with retailing, and a key
regulatory issue is to ensure impartial
procedures for the access of all
aggregators to trading platforms and
agents’ data. Understanding the value
of aggregation is a prerequisite to
addressing the economic viability of
any proposed business model.
Three categories or sources of the
value of aggregation can be identiﬁed:
opportunistic, fundamental and
transitory. Opportunistic value emerges
as a result of regulation or market
design ﬂaws that allow an agent or
aggregation of agents to increase their
economic wellbeing without increasing
– or even decreasing – the economic
efﬁciency of the power system. This is
the case for the rules of allocation of
balancing costs and procurement of
balancing services in some countries.
Netting peak consumption through
aggregation is another example. So
called ‘net metering’ – the combination
of a single standard meter at the
connection point and mostly volumetric
tariffs – results in a substantial subsidy
for the aggregation of demand and
local generation, with the subsidized
amount being passed to the remaining
network users. The only solution to the
‘net metering problem’ is to replace
the standard meter by an hourly one
and to follow the tariff design principles
explained in the previous section.
Other cases of aggregation have value
under present conditions, by increasing
the power system efﬁciency. Examples
include: sharing, among several
agents, some unavoidable costs of
participation in some electricity services
markets; or facilitating the access of
small agents to hedging products; or
eliminating the information gaps or the
threshold size barriers; or promoting
the technical capability to handle all
the relevant information associated
with participation in complex markets.
The fundamental component of the
value remains, since it is intrinsic to
aggregation and is independent of the
market or regulatory context. On the
other hand, the transitory value may
extend some time into the future, but
certain technological or regulatory
improvements will reduce its magnitude
until it disappears.
Conclusion
Any sensible long-term visions of the
power sector should be based on
regulation that correctly implements
any future priorities of energy policy.
Sound regulation will be essential
to efﬁciently blend centralized and
decentralized resources in future
power systems. If regulatory innovation
cannot keep pace with the changing
nature of the electric power system,
large inefﬁciencies may result. In the
absence of regulatory innovation,
network users and new businesses
will ﬁnd ways to arbitrage the growing
disconnect between ill-adapted
‘ANY SENSIBLE LONG-TERM VISIONS
OF THE POWER SECTOR SHOULD BE
BASED ON REGULATION THAT CORRECTLY
IMPLEMENTS ANY FUTURE PRIORITIES OF
ENERGY POLICY.’
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25OXFORD ENERGY FORUM
regulations and new market and
technological realities.
The MIT Utility of the Future Study
is examining an ensemble of power
sector regulatory issues that need
a thorough review, and maybe also
signiﬁcant adaptation, in the presence
of a substantial amount of DERs.
Wholesale markets may have to be
redesigned to include the active
participation of distributed generation,
demand, and storage. Regulators
need to reduce the uncertainty and
the information asymmetry in the
estimation of distribution network
costs, while incentivizing efﬁciency,
but without jeopardizing innovation.
The present organization of the power
sector has to be reconsidered. This
process will include issues such as: the
creation of neutral trading platforms,
data ownership and management,
the more complex new roles of the
Distribution System Operators (DSOs),
the relationship between DSOs and
Transmission System Operators
(TSOs), and the level of separation
between commercial and regulated
network activities when conﬂicts of
interest may exist. Finally, considerable
attention should be paid to the
growing interactions that are already
taking place between the power and
gas sectors, and the buildings and
transportation sectors, each with its
speciﬁc regulations.
Regulation does matter. And most of
the regulation that is mentioned here
has to be supported by quantitative
analysis – such as a portfolio of
computer software tools that can
represent the impact of DERs on
the electric power system under
different geographical and temporal
perspectives. This will be the subject
of another paper.
Wind power and electricity supply security in Colombia
David Harbord, David Robinson, and Ivan M. Giraldo
The current regulatory regime in
Colombia is intended to be technology
neutral, but in reality it is not. This article
describes some of the characteristics
of the Colombian electricity system
and how auctions are used to ensure
sufﬁcient ‘ﬁrm energy’ (the capacity
to produce electricity reliably) to cope
with uncertain hydrological conditions.
It also explains why wind power would
be attractive for the Colombian system
and how current regulations discourage
wind power investment.
The Colombian electricity system and
auctions for ﬁrm energy
Colombia’s electricity system is heavily
reliant on hydro, which accounts
for about 64 per cent of its current
generation capacity and 80 per cent
of electricity produced during normal
weather conditions. There is growing
concern, however, about how to ensure
supply security during periods of low
rainfall, speciﬁcally during El Niño
periods such as occurred in 2009–10,
when hydro’s share of electricity
generation fell to 67 per cent (see the
table below). To avoid shortages, the
missing hydro generation needs to be
replaced with generation from other
sources.
‘THERE IS GROWING CONCERN
ABOUT HOW TO ENSURE SUPPLY
SECURITY DURING PERIODS OF LOW
RAINFALL…’
The traditional source of back-up
has been electricity generated from
thermal power plant burning coal or
natural gas. Many of these plants are
not required to generate electricity
during normal hydrological conditions.
In 2010, which saw the effects of El
Niño at the beginning of the year,
thermal plant accounted for 27 per cent
of electricity generation, while in 2011
(not an El Niño year) this fell by 40 per
cent to 16 per cent of electricity
produced.
Because of their low load factors,
many thermal plants would not recover
their investment costs if they were
being paid for solely on the basis of
revenues earned in wholesale spot and
contract markets. In order to ensure
the building of sufﬁcient generation
Generation output 2010–11 for the Colombian electricity system
2010 2011 Change
GWH
Growth
%GWH % GWH %
Hydro 38,088.6 67 45,583.1 78 7,494.5 19.7
Thermal 15,590.7 27 9,383.7 16 –6,207.0 –39.8
Minor plants 2,985.6 5 3,336.7 6 351 11.8
Cogeneration 222.7 1 316.9 1 94.1 42.3
Total 56,887.6 100 58,620.4 100 1,732.8 3
Source: XM, the company that operates and administers the Colombian wholesale electricity market.
TRANSFORMATION OF THE ELECTRICITY SECTOR
26 OXFORD ENERGY FORUM
capacity, in 2006 the Colombian energy
regulator (the CREG) introduced
a scheme to ensure the long-term
reliability of the electricity supply, and
in particular to guarantee the system’s
ability to meet peak demand during El
Niño periods. The scheme allocates
‘ﬁrm energy obligations’ (OEFs) to
new and existing generation plant
at prices determined in competitive
auctions. OEFs are ‘option contracts’
that commit generating companies to
supply given amounts of energy at a
predetermined Scarcity Price whenever
the spot price in the electricity market
rises above that Scarcity Price. The
companies receive the spot price for
any additional generation above their
ﬁrm energy obligations, and pay a
penalty if they cannot meet their ﬁrm
energy obligations.
In return for agreeing to supply
electricity at the Scarcity Price,
generators with OEFs receive a ﬁxed
annual option fee (the ﬁrm energy
price, or Cargo por Conﬁabilidad) for
each unit contracted. This option fee
makes an important contribution to the
recovery of ﬁxed costs for generating
plants that produce very little in normal
times – such as the CCGT plants
in central Colombia that generate
infrequently outside of El Niño periods.
New plants chosen in the auction have
a guaranteed revenue stream for 20
years, even if they are never required to
generate.
The maximum amount of ‘ﬁrm energy’
that a generator may offer in a ﬁrm
energy auction is known as its ENFICC
(Energía Firme para el Cargo por
Conﬁabilidad). A generator’s ENFICC
refers to the amount of energy of a
given type it can reliably and continually
(in terms of kWh/day) produce during
periods when hydro generation is at
a minimum. It is essentially a lower
bound for the amount of energy that
a given type of plant will be able to
provide at some unpredictable point in
the future. The following table shows
the typical ENFICCs for different
generation technologies in Colombia
as a percentage of a plant’s CEN
(effective net capacity).
To date, there have been two ﬁrm
energy auctions (in 2009 and in 2011).
In the ﬁrst, about 9,300 GWh per year
were allocated to new resources; this
included 1,117 GWh from new coal
plant and 1,678 GWh from new
gas-ﬁred generation plant at an
auction-determined option fee of
13.998 USD/MWh. In the second,
3,700 GWh of OEFs were allocated to
ﬁve new generation projects, with an
option fee of 15.7 USD/MWh. In the
second auction, thermal plant
accounted for over 89 per cent of the
OEFs assigned.
Firm energy from wind power in Colombia
There is growing interest in the potential
for wind power to provide back-up for
hydro, as an alternative to thermal
generation plant. In part this is a
reﬂection of the falling cost of windbased
generation, but it also reﬂects
evidence that wind power potential is
negatively correlated with hydro in
certain regions where wind speeds are
higher during dry periods. There are
also environmental reasons – in
particular lower carbon dioxide
emissions – for preferring renewable
sources of energy to hydrocarbons.
For wind power to be a viable
alternative to thermal generation, the
ﬁrm energy auctions need to accurately
reﬂect the contribution of wind energy
to system security. The challenge is to
determine the quantity of ﬁrm energy
that can be provided by different
energy sources when the system is
under stress, which in Colombia
corresponds especially to peak periods
under El Niño (low hydro) conditions.
For coal and natural gas, which can be
stored, the auction regulations assume
that the plants can provide ﬁrm energy
at about 90 per cent of their rated
capacities. For wind power, on the
other hand, the energy regulator
(CREG) assumes low levels of ﬁrm
energy, about 6 per cent of rated
capacity in 2011. Studies carried out by
the World Bank and by the Oxford
Institute for Energy Studies suggest
that the quantities of ﬁrm energy from
wind in some parts of Colombia are
signiﬁcantly higher, in the range of
20–45 per cent.
The lower the ﬁrm energy attributed to
wind energy, the lower the revenue
streams that can be earned in ﬁrm
energy auctions. If the ﬁrm energy
contribution of wind power has been
underestimated, this acts as a barrier
to investment in wind power in
Colombia, and indirectly raises the cost
of meeting system security. The
ﬁnancial consequences for investors
are signiﬁcant. Following the 2011
CREG approach (at a 6.3 per cent ﬁrm
energy rating), a 100 MW wind plant
would earn approximately USD735,734
per annum in guaranteed payments for
20 years at the ﬁrm energy price
(13.998 USD/MWh). Using an approach
to measuring ENFICCs that was
proposed by the World Bank for
Colombia (which resulted in a 36 per
cent ﬁrm energy rating) a 100 MW wind
plant would earn approximately USD4.4
million in annual ﬁrm energy payments.
This makes a signiﬁcant difference to
the ﬁnancial viability of wind farms in
Colombia.
ENFICC % for different
technologies as of 2012
Technology
Maximum
ENFICC (%)
Hydro with storage 55
Hydro without storage 30
Coal 97
Natural gas 93
Fuel oil 88
FEBRUARY 2016: ISSUE 104
27OXFORD ENERGY FORUM
The question is whether the CREG
really does underestimate the
contribution of wind power to system
security. To assess this, the authors
looked at the relevant economic
principles and at selected international
experience.
Economic principles and international
experience
There is no universally accepted
method for calculating the contribution
of intermittent generating technologies
(such a wind) to system reliability.
However, there are some basic
principles that guide the methodology
to be used, as well as experience
in the application of this
methodology.
‘THERE IS NO UNIVERSALLY ACCEPTED
METHOD FOR CALCULATING THE
CONTRIBUTION OF INTERMITTENT
GENERATING TECHNOLOGIES TO SYSTEM
RELIABILITY.’
The main principle for calculating the
contribution of wind power to system
reliability is to reﬂect the amount of
ﬁrm energy the system can rely on
when there is a high risk of shortages.
In most systems, this occurs during
periods of peak demand. However, in
Colombia, the probability of shortage
is highest during El Niño periods – in
other words when hydro generation is
low. So the question is how much ﬁrm
energy can be provided by wind power
in those periods.
One way of calculating a ﬁrm energy
factor is to use historic data to
determine the minimum amount of
energy that can be provided by wind
power in periods of system stress.
Each system has different periods of
shortage, and each wind power station
within a system will have output that
coincides, more or less, with those
shortage periods. To the extent that
wind generation is higher at times of
shortage, the plant will have a higher
ﬁrm energy factor.
There are different ways to use the time
period-related data to approximate
wind’s ﬁrm energy factor. One method
that we think is sensible is used in
PJM (the Pennsylvania–New Jersey–
Maryland Interconnection, a regional
transmission organization in the USA).
This approach averages the windrelated
generation over the relevant
shortage periods in recent years in
order to estimate the level of ﬁrm
energy that can be expected during a
period of system stress.
Application of the PJM methodology to
Colombia
The relevant shortage periods in
Colombia are mainly El Niño periods,
especially during peak hours.
Following the logic of the PJM
approach, we estimated the ENFICCs
for wind power using hourly generation
data from the experimental Jepírachi
wind farm in Colombia’s Guajira region,
between April 2004 and April 2011.
The ENFICC estimate (shown in
the table below) uses the PJM
methodology, applied to wind output
on a daily basis and during peak
hours during the last three El Niño
periods. This yields average estimates
of ENFICC between 27 per cent and
33 per cent, compared to the CREG’s
estimates of below 15 per cent.
This suggests that the CREG’s original
2011 methodology, with ENFICC below
15 per cent is too conservative. Both we
and the CREG measure ‘ﬁrm energy’. In
their original methodology, the CREG
measures it by reference to the lowest
average monthly (in kWh-day) ﬁgure for
output from the pilot wind plant; their
ENFICC thus has a 100 per cent (or 95
per cent) probability that wind output
would be greater than the historic
minimum. That plant-speciﬁc probability
is too low because system reliability
depends on the probability of the
combination of plants providing energy,
not simply on the probability related to
an individual plant. This is especially
important when there is an inverse
correlation between wind and hydro
generation. Recently, the CREG has
changed its methodology and increased
the ENFICC for wind. However, UPME, a
government body responsible for
long-term planning, argues that the
methodology is still very conservative
and ignores the complementarity
between wind and hydro generation.
In contrast, we measure ﬁrm energy
(using the PJM methodology) by
reference to the historic average wind
output during the periods of signiﬁcant
system stress – which occur during El
Niño periods. By narrowing our focus
to periods when the systems is under
stress, our ENFICC reﬂects wind’s
contribution to system reliability when
hydro generation is low.
PJM methodology to determine ENFICC for wind power in Colombia
ENFICCs base 5–7 a.m.; 6–8 p.m. All day
Niño 1 24.13% 29.05%
Niño 2 27.32% 37.02%
Niño 3 30.34% 33.78%
Average 27.26% 33.29%
5–7 a.m.; 6–8 p.m. All day
All 3 Niños 27.52% 32.58%
TRANSFORMATION OF THE ELECTRICITY SECTOR
28 OXFORD ENERGY FORUM
Conclusion
At the beginning of 2014, wind power
in Colombia (all from the experimental
Jepírachi plant) accounted for only
0.1 per cent of total generation
capacity. There are new wind projects
under study, with the potential to
generate up to 674 MW (as of July
2015), but none have yet entered the
construction phase. However, the
current very high energy prices – which
are the result of reliance on diesel
oil-ﬁred generation to replace hydro
power during the current El Niño event
– reinforce the need for a more
diversiﬁed energy mix, which would
include alternative sources like wind
power.
We think the reluctance to invest
is at least partly due to the current
regulations in Colombia, which
underestimate wind power’s potential
contribution to electricity system
security. Given the recent evidence
of the Colombian government’s
commitment to develop alternative
energies, particularly wind power, and
its tradition of technological neutrality,
the authors encourage a regulatory
rethink, in particular to recognize the
complementarity among renewable
resources in their contribution to
system security. If this cannot be
done through the reliability auctions
due to complexity or for other reasons,
then other regulatory measures
should be considered to take
account of this complementarity and
to lower barriers to investment in
wind power.
Decarbonization through electriﬁcation – the importance of energy
taxation being in line with long-term energy policy
Graham Weale
Electriﬁcation as a major instrument for
decarbonization
With the success of the COP21 Meeting
in Paris the world has shown itself more
determined than ever to combat climate
change. Europe has been at the
forefront of this initiative since the late
1990s and in 2010 the landmark
Roadmap 2050 was published by the
European Climate Foundation, showing
how the EU could achieve its 80 per
cent decarbonization aim. At the heart of
the plan lay a greatly enhanced role for
progressively decarbonized electricity
within the overall energy supply.
Electricity would be needed to play a
leading role in transport (supported by
biofuels and fuel cells) and also in the
space heating sector through the
installation of heat pumps.
According to the Roadmap, electricity
demand would increase by up to
40 per cent against the baseline by
2050, with an additional 740 TWh and
700 TWh being required respectively
for transport and heating (in both the
household and industry sectors).
This prospective growth of over
1400 TWh should be put in the context
of ﬁnal electricity demand in the EU-28
of 2843 TWh (2010) and 2771 TWh
(2013).
Whilst there are alternative solutions for
the future supply mix – whether there
should be more emphasis on
renewables outside the power sector or
whether hydrogen may become an
important fuel for the transport sector
– there is widespread agreement that
substantial electriﬁcation will be crucial.
It then becomes important to see
whether the conditions are in place to
allow this to be achieved and the
necessary infrastructure built up
smoothly along the way, rather than
being challenged by short- or mediumterm
declining electricity demand.
The current energy taxation policy is
hindering electriﬁcation
The statistics for European electricity
demand in 2010 and 2013 cited above
point to an initial decline in demand rather
than the start of a new electriﬁcation
trend. One factor contributing to this
development is that the energy carrier in
several countries (notably in Germany) is
loaded with considerably more tax and
other surcharges than competitive energy
carriers. Excise taxes on vehicle fuels are
renowned for being high, but (at least in
Germany) these have now been
overtaken by the taxes and surcharges on
electricity for electric vehicles.
Two important messages concerning the
market share of electricity in the ﬁnal
energy consumption mix are seen in
graph overleaf. Most noticeable are the
very different positions which electricity
holds in different countries – 34 per cent
in Sweden and 20 per cent in the UK
– results which have not generally arisen
due to conscious planning on the part of
government. Only in France was a policy
introduced to place emphasis on the role
of nuclear electricity as a central means of
primary energy supply, in response to the
1973 oil supply crisis; this led naturally to
a relatively high electricity market share.
Sweden has a high electricity share due
to a very limited gas supply, abundant
FEBRUARY 2016: ISSUE 104
29OXFORD ENERGY FORUM
hydropower, and a policy of not overtaxing
this form of energy.
‘…ELECTRICITY’S MARKET SHARE IN
ALL FOUR OF THE LARGEST EU
ECONOMIES IS STARTING TO DECLINE.’
The second message from the graph
is that electricity’s market share in all
four of the largest EU economies is
starting to decline. Of course there
could be various reasons for this, but
the classical price elasticity effect – due
entirely to taxation and surcharges – is
certainly one factor.
The graph on the right shows clearly
by how much electricity taxes and
surcharges have increased over the
last ﬁve years (far more than those on
gas), principally as a result of
renewables development in the
sector. Eurostat has applied a
particular deﬁnition of taxes and
surcharges and therefore small
differences may be noted when
compared with other sources. For
example, according to UK DECC
Statistics in 2013 the total levies
amount to 0.026 EUR/kWh.)
The development of sound energy
policy is challenging at the best of
times, and it is difﬁcult to anticipate
all the side effects every time. The
particular means of implementing and
ﬁnancing national targets for
renewables in various EU countries is a
case in point, where the focus has
been on meeting renewables targets
and ﬁnancing them by consumer levies.
It has proved practical to reach those
national targets for renewables by
concentrating on electricity, while some
countries had the additional aim of
replacing certain forms of thermal
power generation. As a result, in the
EU-28 over the period 2004–13 the
renewables share of the power sector
increased by 11.1 per cent; at the same
time, the increase in the heating sector
was 6.6 per cent, while that in the
transport sector was 4.4 per cent.
Both Germany and the UK saw twice
as much growth in the renewables
share in their power sectors as in
their heating and transport sectors
together. Conversely in Sweden much
more emphasis has been given to the
heating and transport sectors.
These developments in themselves
are not necessarily to be criticized,
but the consequence which now
deserves attention (and which was
most likely not originally considered),
is the relative increase in the
end-consumer price of electricity
as compared to competing sources
of energy (mainly gas and oil
products). Higher prices of energy in
general increase the incentive for
energy efﬁciency investments, an
evidently positive outcome. However,
high relative prices of electricity risk
setting in motion a development that
may threaten the long-term goal of
19%
21%
23%
25%
27%
29%
31%
33%
35%
2009 2010 2011 2012 2013
EU(28)
Germany
Spain
France
Italy
Sweden
UK
Market share of electricity in ﬁnal energy consumption
0
0.02
0.04
0.06
0.08
0.1
0.12
0.14
0.16
0.18
0.2
EUR/kWh
Gas2015
Gas2010
Elec2015
Elec2010
Taxes and surcharges on electricity and gas – household consumers
Note: Values for 2015 are incremental over those for 2010. Denmark’s value for gas in 2015 was lower than its
2010 value (0.483 EUR/kWh). Figure 2 shows the 2010 value.
Source: Eurostat – Prices and Taxes for Household Electricity and Gas Consumption.
TRANSFORMATION OF THE ELECTRICITY SECTOR
30 OXFORD ENERGY FORUM
decarbonization through electriﬁcation.
In the worst case it could trigger the
so-called ‘utility death-spiral’ (an
expression coined in the USA as the
growth of consumer PV ate into utility
revenue and proﬁts), whereby
infrastructure (required both to deliver
centrally generated electricity and to
support the growing decentralized
generation) would struggle to invest as
required for the longer-term
electriﬁcation goals.
The problem of the rising taxes and
surcharges on renewables, shown in
the second graph, can be
compounded by two further factors
that can make the situation even
more serious. Both relate to
developments in the tariffs for the
distribution networks.
The ﬁrst factor at play in some
countries is the cost of connecting
renewables, when this is borne by
the customers rather than the project
developers and therefore translates
into higher network charges. In
Germany (including VAT), these
charges have increased by up to
0.02 EUR/kWh between 2010 and
2015 to accommodate the increased
number of windfarms, the production
of which is essentially exported to
southern Germany, with the local
consumers enjoying absolutely no
beneﬁts (other than modest
employment effects).
The second factor relates to the
pernicious consequence of having
to spread a ﬁxed cost operation
(of which the power industry is
becoming an example par
excellence as the role of fossil fuels
decreases) over progressively fewer
units of energy. There are two
elements at work here. First is the
increase in self-generation, reducing
the net consumption ﬂowing from
central sources through the grid.
The second is the decline in gross
power generation; this has been
catalysed by both the price elasticity
effect (an incentive to reduce
electricity consumption, together
with other energy efﬁciency
initiatives), and the incentive to
favour, in relative terms, other forms
of energy (the cross-price elasticity
effect), whether by switching away
from electricity or not switching to it
(for example, heat pump
applications).
The issue of the price elasticity effects
coming into play and working against
longer-term electriﬁcation appears not
yet to be showing up on government
radar screens. If the current early trends
continue, there is the risk that switching
away from electricity may gather
momentum, leading to developments
which are in contradiction to the longerterm
electriﬁcation aims, before such
switching can be slowed down and
reversed.
‘IF THE CURRENT EARLY TRENDS
CONTINUE, THERE IS THE RISK THAT
SWITCHING AWAY FROM ELECTRICITY
MAY GATHER MOMENTUM…’
Electriﬁcation, as one important means
of decarbonization, will most likely take
place at the lowest cost if there is a
smooth development from the current
position out towards 2050. Therefore,
the right long-term signals need to
be put in place to incentivize the
progressive development of electricity
infrastructure, rather than its premature
downsizing.
Solution: bringing energy taxation policy
into line with energy and climate policy
How then can progress towards
meeting EU and national renewables
targets be maintained and longer-term
decarbonization be kept on track?
The answer lies in a root and branch
review of energy taxation policy, which
would include renewables surcharges.
Fortunately, even without designing
potential new systems there is a helpful
range of policies (whether actual or
under discussion) from which to draw.
Option 1: Supporting renewables from
general taxation
Turning ﬁrst across the Atlantic, the
policy in the USA has been to support
renewables mainly out of general
taxation. Onshore wind farms currently
beneﬁt from production tax credits
which are worth around 25 USD/MWh,
and solar plants from 30 per cent
investment tax credits. The result is that
renewables have grown without
increasing the consumer price of
electricity and thereby reducing its
market share. Of course there have
been other side effects of the policy.
Long-term Power Purchase Agreements
(PPAs) for wind power have been
signed at 25 USD/MWh or even lower,
and these have artiﬁcially brought down
the wholesale price, which has put
certain thermal plants, in some cases
even nuclear, under pressure.
Option 2: Technologically neutral quota
systems
Within Europe, whilst feed-in tariffs
have been the rule, some countries
(such as Sweden and the UK) have
followed quota systems. Sweden
is one of the few countries to have
followed a technologically neutral
quota system. This led to a focus on
a single technology at any given point
in time: ﬁrst biomass (2000–7) and
then onshore wind. Other countries,
in contrast, opted for the parallel
development of more than one type of
technology; this has the advantage that
some of the more challenging forms
of technology (such as offshore wind)
which are essential to meet climate
goals, have a greater chance of being
successfully developed, and of being
brought to commercial maturity more
quickly, than under a technologically
neutral support system. But it increases
the costs over the short term.
FEBRUARY 2016: ISSUE 104
31OXFORD ENERGY FORUM
Even though the quantities of
renewable electricity which Sweden
has developed on the basis of
technological neutrality are modest, its
average support costs are low, at only
24 EUR/MWh. This compares with a
weighted average of 95 EUR/MWh for
the eight EU countries with, in total,
the most renewables, while the ﬁgure
for Italy – at 177 EUR/MWh – is almost
twice as high.
Option 3: Spreading the cost of
renewables across all forms of energy
France has an electricity surcharge:
CSPE (Contribution au Service
Public de l’Électricité). Approximately
two-thirds of this surcharge covers
renewables, the remainder goes
towards other costs to be socialized
(such as the higher costs of
electricity in the French islands and
cogeneration). The level of the CSPE
was 0.02 EUR/kWh in 2015 (less than
one third of the German equivalent) but
there is an ongoing discussion, partly
because electricity prices are politically
particularly sensitive, as to whether the
cost of the renewables subsidy should
be spread over more (or potentially all)
forms of energy.
‘EVEN IN THE USA THE FUTURE OF
FURTHER TAXATION SUPPORT IS FAR
FROM CERTAIN…’
Whilst the public taxation option has
some compelling logic, the efforts
being made by almost every national
Finance Ministry to reduce their budget
deﬁcit makes it an unlikely runner. Even
in the USA the future of further taxation
support is far from certain, and at the
time of writing the US legislators were
considering a plan to phase out all tax
support over ﬁve years, with support
for solar power potentially disappearing
sooner.
The most realistic option then, one
which should certainly be addressed,
is a careful reform of energy taxation
with the aim of ensuring maximum
consistency with long-term energy and
climate policy. There are a number of
dimensions to such a reform which
need to be considered:
(a) The need to avoid disadvantaging
electricity by taxing it
disproportionately in relation to
other fuels – the main theme of
this paper.
(b) Ensuring, over the long run, that the
price of different forms of energy is
close to the full cost, including
externalities.
(c) The need to ensure, above all else,
a strong incentive for energy
efﬁciency (but not for any
particular fuel, other than as
dictated by its overall carbon
footprint).
This would mean, ﬁrst, that there should
not be fuel-speciﬁc taxes – such as
an electricity tax rather than a gas tax.
Also, to the extent that taxes as such
would have revenue-raising objectives,
then they should be proportional to the
energy element. (There is a different
argument in the case of motor fuels
where taxes are needed to pay for the
road infrastructure.)
There may appear, at ﬁrst sight, to
be a contradiction between (a) and
(b) above, but renewables raise the
challenge that they originally needed
support (and to some extent still do)
in order to bring them to commercial
maturity. So far as the support required
for this purpose, as opposed to the
future steady-state ﬁnancing costs, can
be separated, the author is arguing
that such learning costs should either
be spread over all forms of energy or,
where possible, covered from general
taxation. In Germany, for example,
almost half of the current annual
0.063 EUR/kWh renewables support
charge relates to the legacy support
for PV. This cost component has no
relationship to the long-term costs
of renewables electricity generation
and including it as part of the ﬁnal
consumer electricity price (including
VAT, it represents around 12.5 per
cent of the price) is inconsistent with
objective (b) above.
The multiple political and environmental
requirements placed on the energy
system, and in particular on the
power system, militate against a
clean economic solution. In the
previous decade, the EU aimed,
through market-based methods, to
meet the welfare objectives of the
Single Market (through the internal
wholesale market – with progressive
improvements to its working) and
the objective of decarbonization
(through the carbon emission trading
system). However, these were quickly
and comprehensively usurped by
various out-of-market mechanisms.
It is now unrealistic to expect too
much emphasis to be placed on
the (originally foreseen) simple
and fundamentally market-based
methods to meet power demand and
decarbonize.
‘…THE NEED FOR ENERGY TAXATION TO
BE IN HARMONY WITH ENERGY POLICIES
AND STRATEGIES HAS SO FAR BEEN
COMPLETELY OVERLOOKED.’
However, whilst the wholesale markets
have been heavily distorted, leaving
them poorly equipped to achieve
much more than the optimal
dispatching of existing plants, other
economic forces are still very much
at work, including the aforementioned
price elasticity effects, which cannot
be ignored.
European governments are being
challenged in many different directions,
both by requirements to meet their
speciﬁc 2020 goals, together with
national policy objectives. There is
thus the risk that they give inadequate
attention to the strategies required
TRANSFORMATION OF THE ELECTRICITY SECTOR
32 OXFORD ENERGY FORUM
to reach the 2050 end goal of 80–95
per cent decarbonization (and at a
reasonable cost), and are pulled off
course. The longer-term importance
of the need for energy taxation to be
in harmony with energy policies and
strategies has so far been completely
overlooked. It is now time to open
this book and make the necessary
corrections so that, over time, there will
be a smooth and optimal cost path to
the 2050 goals.
View from the USA: rapid transformation of power sector calls for
new tariffs
Fereidoon P. Sioshansi
Conventional electricity tariffs
It should come as no surprise to
anyone that the cost of providing
electric service to most customers
– notably residential consumers – is
mostly ﬁxed. Studies by the Electric
Power Research Institute (EPRI) and
others put the ﬁxed component of
the cost at around 60 per cent for the
typical residential user in the USA,
which is the main focus of this article.
What is surprising, however, is that for
over a century, for most consumers,
the bill has been mainly determined
by the volume of electricity consumed:
a multiplier (cents/kWh) times the
number of kWhs used. Even today,
most residential consumers in the USA
pay virtually all their monthly bills on
the basis of volumetric consumption.
Relatively little is collected through ﬁxed
fees or connection charges.
‘THE COST OF PROVIDING ELECTRIC
SERVICE TO MOST CUSTOMERS –
NOTABLY RESIDENTIAL CONSUMERS –
IS MOSTLY FIXED.’
The volumetric scheme did not make
much sense when it started, but was
a convenient way to measure and bill
consumers. For regulators, it was an
easy way to adjust the ‘multiplier’ every
so often to reﬂect changes in fuel,
operating, or investment costs. For
consumers, the concept made sense.
Many still believe that electricity should
be billed on the basis of volume, as
with gasoline. If you don’t use much,
you don’t pay much.
It did not much matter throughout
the industry’s formative decades,
when demand continued to grow,
encouraging massive investments
in generation and in transmission
and distribution infrastructure, which
could be ﬁnanced through the simple
volumetric scheme. With average retail
tariffs ﬂat or declining in real terms and
rapid demand growth, everyone was
happy – the consumers, the utilities,
and the regulators.
Effects of distributed generation
Conditions are different today.
Electricity demand in the USA – and in
nearly all other mature economies – is
virtually ﬂat or in some cases actually
declining (see the table below). As
buildings and appliances become
more efﬁcient, less energy is needed to
operate them. Moreover, with the rapid
fall of the cost of distributed generation
(DG), notably in rooftop solar
photovoltaics (PVs), consumers can
produce more of what they consume,
which means less is bought from the
network, the grid.
While the impact of DG is uneven, in
some places its effects are becoming
pronounced. For example, Energex,
a distribution utility serving the
Brisbane metropolitan area in sunny
Queensland, Australia already has
nearly 300,000 customers with rooftop
solar PVs, making it among the highest
on a per capita basis.
Making matters worse is the massive
cost of maintaining and upgrading
an ageing infrastructure upstream of
the meter – the costs of which must
be spread across a shrinking base.
This leads to higher retail tariffs, which
Get used to it: no growth in utility business – New York or elsewhere
Average electric sales growth in New York, 1966 to 2013 and projections to 2024
Period Avg. sales growth for period
1966–76 3.8%
1976–86 1.5%
1986–96 1.4%
1996–2006 0.9%
2003–2013 0.3%
2014–2024 0.16%
Source: New York Public Service Commission, 26 February 2015.
FEBRUARY 2016: ISSUE 104
33OXFORD ENERGY FORUM
encourages more investment in energy
efﬁciency and DG, which leads to
even higher tariffs – the so-called utility
death spiral.
‘ELECTRICITY TARIFFS ARE THUS IN NEED
OF OVERHAUL AS CONSUMERS BUY LESS
AND GENERATE MORE.’
Not surprisingly, consumers in many
European countries, where electricity
is heavily taxed and/or loaded with
levies, are also looking for any
measure at their disposal which would
enable them to buy less; this means
using less and self-generating more
when it is cost-effective to do so.
Electricity tariffs are thus in need of
overhaul as consumers buy less and
generate more.
Future of electricity tariffs
In this context, the debate on what
to do with electricity tariffs is heating
up in many parts of the world, as
regulators and politicians grapple with
ﬁnding ways to keep the incumbents
solvent without necessarily crushing
the rapid uptake of solar PVs, which
are enormously popular among
consumers.
A recent article in The Wall Street
Journal (20 October 2015), entitled
‘As Conservation Cuts Electricity
Use, Utilities Turn to Fees’, described
the dilemma faced by utilities and
regulators in the USA as they try to
adjust consumer tariffs by shifting more
of the costs of service to ﬁxed fees –
which is how it should have been in the
ﬁrst place. It said:
Electric utilities across the country
are trying to change the way
they charge customers, shifting
more of their ﬁxed costs to
monthly fees, raising the hackles
of consumer watchdogs and
conservation advocates.
Traditionally, charges for
generating, transporting and
maintaining the grid have been
wrapped together into a monthly
cost based on the amount of
electricity consumers use each
month. Some utilities also
charge a basic service fee of
$5 or so a month to cover the
costs of reading meters and
sending out bills.
Now, many utility companies are
seeking to increase their monthly
fees by double-digit percentages,
raising them to $25 or more a
month regardless of the amount
of power consumers use. The
utilities argue that the fees
should cover a bigger
proportion of the ﬁxed costs
of the electric grid, including
maintenance and repairs.
The basic logic of what the utilities
are trying to do makes sense, but
changing utility tariff structures is
complicated, slow, and convoluted.
Making matters worse, it is highly
political. Any change in current tariffs
means shifting costs to other
customers, who do not like paying
more.
Many believe that the electricity grid is
essentially a public good and,
therefore, must be paid for by everyone
who beneﬁts from it.
Utilities in at least 24 states have
requested higher fees. Confronted with
the facts, regulators in a number of
states are sympathetic to the plight of
utilities but are reluctant to raise ﬁxed
fees too aggressively.
Fixed fees have their critics. Consumer
advocates point out that they
disempower the customer and
discourage investments in rooftop solar
and energy efﬁciency.
Fundamentally, the thinking is to
move towards tariffs that reﬂect
cost-causality so consumers get
charged for the costs they impose on
the network while raising sufﬁcient
revenues for the maintenance and
upgrading of the grid and the
reliability that it offers. These include
several well-known tariff options
such as:
Time-of-use (TOU) rates;
Increased ﬁxed charges;
Three-part tariffs; and
Demand subscription.
Three-part tariffs are getting some
traction as they purport to closely
follow the costs attributed to serving
customers in the emerging business
environment. One such tariff introduced
by the Salt River Project (SRP), a nonregulated
utility operating in Arizona, for
example, consists of the following three
components:
A ﬁxed charge of USD18–20
regardless of usage level, peak
demand, or anything else. It may be
considered a connection or network
fee;
An energy charge, slightly lower than
the previous volumetric charge, to
recover the variable cost of fuel and/
or purchased power; and
A demand charge, which varies
based on how customers’ peak
demand coincides with the network’s
peak demand.
For a customer with an 8.5 kW solar
panel, for example, the demand
charge varies from USD41/month in
the winter to USD126/month in the
summer.
‘THE REGULATORS DO NOT WISH TO
ANGER THE SOLAR CUSTOMERS BUT
ARE BECOMING SENSITIVE TO THE
PLIGHT OF THE UTILITIES…’
Other states examining three-part
tariffs include Nevada. Describing the
TRANSFORMATION OF THE ELECTRICITY SECTOR
34 OXFORD ENERGY FORUM
merits of its recent application for solar
customers ﬁled with the Public Utilities
Commission of Nevada (PUCN) in
early August 2015, Kevin Geraghty,
NV Energy’s vice president of Energy
Supply said:
A three-part rate design better
reﬂects the unique costs of
serving our net metering
customers and eliminates the
unreasonable shifting of costs
between those that can access
rooftop solar and net metering
and those that don’t, [adding
that] This is a proven rate
structure that has been in use
by our commercial customers
for more than 50 years. Under
the proposal, net metering
customers still have the
opportunity to reduce their bill
from NV Energy if they reduce the
impact they have on the grid.
The regulators do not wish to anger
the solar customers but are becoming
sensitive to the plight of the utilities
which are suffering from revenue
erosion while higher costs are being
shifted to non-solar customers. The
battle is just beginning.
A comparison of US and EU electricity prices: the relevance of the
government wedge
David Robinson
This article is a short English summary
of my recent report, published in
Spanish (‘Análisis comparativo de los
precios de la electricidad en la Unión
Europea y en Estados Unidos: Una
perspectiva española’), comparing
trends in ﬁnal electricity prices in the EU
and the USA over the period 2008–14.
The article explains why ﬁnal consumer
electricity prices in the EU, especially in
Spain, increased signiﬁcantly more than
in the USA between 2008 and 2014.
168
47
44
25
24
23
18
13
12
11
0 50 100 150 200
Hawaii
California
Arizona
NewJersey
Colorado
Vermont
Massachusetts
Louisiana
Connecticut
Maryland
Wattspercapita
Sunshine states: states that get most electricity per capita from
residential solar panels, 2014
Source: Rebecca Smith and Lynn Cook, ‘Hawaii wrestles with vagaries of solar power’, The Wall Street Journal, 29
June 2015.
90
100
110
120
130
140 Residential -EurostatDD
90
100
110
120
130
140 Commercial -EurostatIB
EU28 USA
90
100
110
120
130
140 Industrial -EurostatID
1. Evolution of average ﬁnal electricity prices in the EU and the USA, 2008–14
Source: Eurostat and US DOE-EIA
FEBRUARY 2016: ISSUE 104
35OXFORD ENERGY FORUM
It concludes that the primary
explanation is not related to
differences in conventional
determinants of electricity price (the
demand for and the cost of wholesale
electricity and networks) but rather to
differences in taxes, levies, and other
charges related to ﬁnancing public
policies, notably support for
renewable power.
Comparing ﬁnal prices
Graphic 1 includes electricity price
indices for residential, commercial
and industrial consumers in the two
regions since 2008. They illustrate
clearly that average prices in the EU
have risen signiﬁcantly faster than in
the USA. For instance, prices for
residential consumers rose by 34
per cent in the EU (EU 28) and by
18 per cent in the USA. For industrial
consumers, average electricity prices
rose by 22 per cent in the EU and by
6 per cent in the USA.
‘…AVERAGE PRICES IN THE EU HAVE
RISEN SIGNIFICANTLY FASTER THAN IN
THE USA.’
At the beginning of the period, US
prices were much lower than in the EU.
By the end of the period, the difference
was even greater, with average EU
prices approximately twice as high as
in the USA for each of these customer
categories (see Graphic 2).
Why is there a large divergence in ﬁnal
price trends?
I consider various possible
explanations for divergent price trends,
including differences in electricity
demand and in the two most important
costs of electricity supply: wholesale
electricity market prices and the cost of
networks.
Demand
The average demand per household
in the USA is more than twice the
average level in the EU (4,137 kWh in
2009). Since the electricity industry has
high ﬁxed costs, higher volumes for
any given ﬁxed costs usually translate
into lower unit costs and prices, as
illustrated by Graphic 3, which plots
prices and consumption per household
in the US states.
Although lower EU consumption per
household may help to explain higher
average prices at any given time, it
does not explain why average EU
prices have risen so much faster than
0.00
0.05
0.10
0.15
0.20
0.25
Residential
EurostatDD
Commercial
EurostatIB
Industrial
EurostatID
€/kWh
EU28 US
2. Final electricity prices in the EU and the USA, 2014-S2
Source: Eurostat and US DOE-EIA
0
50
100
150
200
250
300
350
400
6,000 8,000 10,000 12,000 14,000 16,000
Averageprice($/MWh)
Averageannualconsumption(kWh)
3. Price per MWh versus average annual electricity consumption per household in US states
TRANSFORMATION OF THE ELECTRICITY SECTOR
36 OXFORD ENERGY FORUM
in the USA since 2008. If US electricity
demand had grown signiﬁcantly faster
than in the EU, this might help to
explain the faster rise in EU average
prices. In fact, US electricity demand
was approximately the same in 2014
and in 2008, whereas EU electricity
demand fell by about 3 per cent over
the period. That difference may explain
a small part of the price divergence,
but not very much. For instance, if the
ﬁxed costs of networks were 30 per
cent of the ﬁnal price, a difference of
3 per cent in demand growth would
translate into an increase of about
1 per cent in the ﬁnal price.
Wholesale market prices
The availability of low-cost shale gas
helps to explain why US wholesale
electricity prices have not risen
since 2008 – indeed, in nearly all US
wholesale markets, they have fallen, as
illustrated in the right side of Graphic
4. However, this does not explain the
difference in ﬁnal consumer price
trends because wholesale electricity
prices follow a similar pattern of ﬂat or
falling prices, depending on the dates
chosen, in both the USA and the EU.
In the EU, prices have been depressed
by a combination of excess generation
capacity, low coal and carbon dioxide
emission allowance prices, depressed
demand, and high penetration of
intermittent renewable electricity.
Network costs
The costs of transmission and
distribution networks have increased
in the EU and the USA at roughly the
same rates over the period, so they do
not explain the diverging price trends.
I conclude that the diverging paths of
ﬁnal prices between the USA and the
EU cannot be explained convincingly
by any of the traditional demand or
supply cost factors, alone or together.
The government wedge
The term ‘government wedge’ refers to
taxes, levies, and other charges that
ﬁnance public policies through the
electricity tariff. The wedge does not
include the cost of policies that are
ﬁnanced through the government
budget; it only covers those costs that
are ﬁnanced through tariffs. The wedge
is the third component of electricity
prices, with the other two being
competitive energy prices (for
wholesale energy and retail services)
and regulated network costs.
The government wedge has been
growing steadily in most European
countries since about 2008. According
to the electricity industry lobby
Eurelectric, between 2008 and 2012 the
government wedge rose by 31 per cent
for residential consumers and by over
100 per cent for industries, whereas
wholesale energy costs fell and network
costs rose by only 10 per cent and
17 per cent for residential and
industrial consumers, respectively.
To take one example: in Spain,
ﬁnal electricity prices for residential
consumers have risen by over 50
per cent since the end of 2008. The
government wedge explains over 70
per cent of the increase and in 2014
it accounted for 46 per cent of the
ﬁnal price for these customers. VAT
and special electricity taxes are the
most important component of the
wedge for residential consumers.
Then comes the ﬁnancial support for
renewable electricity and cogeneration,
and interest payments on the EUR25
0
20
40
60
80
100
120
140
Spain Italy
Germany France
0
20
40
60
80
100
120
140
PJM(load-weightedaverage)
ISO-NE(WCMassachusetts)
CALIFORNIA(SP15-SOUTH)
ERCOT(LZNorth-Texas)
4. Selected EU and US wholesale electricity market price indices, 2008–14
Sources: OMIE, EEX, GME, ERCOT, PJM, CAISO, ISO-NE, MorningStar
‘THE TERM “GOVERNMENT WEDGE”
REFERS TO TAXES, LEVIES, AND OTHER
CHARGES THAT FINANCE PUBLIC
POLICIES THROUGH THE TARIFF.’
FEBRUARY 2016: ISSUE 104
37OXFORD ENERGY FORUM
billion tariff deﬁcit (in other words,
the accumulated difference between
regulatory entitlements and the
tariffs set to collect the cost of these
entitlements). The wedge also includes,
inter alia, funding for domestic coal
suppliers, compensation for higher
costs of supply on the islands, and
payments to certain consumers.
The government wedge in the USA is
difﬁcult to measure, largely because
published data for the sector bundles
any policy-related costs into the
categories of generation, transmission,
and distribution. It is also difﬁcult to
compare states which have vertically
integrated and regulated electricity
monopolies with states that have
unbundled the sector and have
competitive wholesale or retail markets.
Nevertheless, the available evidence
suggests that the wedge is much
smaller in the USA than in the EU. The
ﬁrst piece of evidence is the greater
investment in, and penetration of,
intermittent renewable energy in the EU,
as illustrated in Graphic 5. On average,
intermittent renewables account for
more than 6 per cent of EU electricity
generation and for less than half that
percentage ﬁgure in the USA.
Second, the USA ﬁnances an
increasingly signiﬁcant part of the
costs of renewable power and other
public policies (such as energy
efﬁciency and smart grids) through
federal and state taxes, rather than
through electricity tariffs. Total federal
subsidies for renewable power – both
direct payments and tax credits – were
over US$11.7 billion in 2013, up from
about US$1 billion in 2007. The federal
government also provided subsidies
of US$1.2 billion for smart grids and
transport in 2013. The US Congress
has recently extended the regime of
investment credits for solar energy and
production credits for wind power.
In addition to federal subsidies for the
power sector, there are many state-level
subsidies. Texas, for instance, offers tax
credits for renewable power that were
worth approximately US$1.4 billion in
2013, up from about US$700 million in
2007.
Third, most European countries levy
VAT and other taxes on electricity
consumption, whereas in the USA
electricity is often not taxed, or is taxed
at a much lower level. The average
VAT levied on electricity in the EU rose
from 15 per cent in 2008 to 17 per
cent in 2012. This is not an issue for
commercial and industrial consumers
since they can recover these taxes.
However, it does have an important
impact on residential consumers who
are unable to recover these taxes.
Implications and recommendations
The immediate consequence of rising
prices in the EU has been to reduce
the disposable income of residential
consumers, especially in countries with
a very high penetration of renewable
power, notably Germany and Spain.
Although industry and commerce
have also seen rising prices, the bulk
of the extra costs have been born by
residential consumers. This is the case
in Spain, as illustrated by Graphic
6, where the top part of the graphic
reﬂects the government wedge, with
the residential consumers on the left,
commerce in the middle, and industry
on the right hand side.
A second implication is the distorting
effect on energy markets. Facing ﬁnal
prices that exceed the (long or short
run) marginal costs of electricity supply,
consumers are encouraged to behave
in ways that are not efﬁcient, in
particular to discourage the use of
electricity and instead to encourage
consumption of fossil fuels, for instance
in heating. If the EU is to achieve its
political objective of reducing
greenhouse gas emissions by 80–95
per cent by 2050, this will require
almost complete decarbonization of the
electricity sector and large-scale
electriﬁcation of transport, heating, and
even industrial energy consumption.
0
50
100
150
200
250
300
350
TWh EU28
0
50
100
150
200
250
300
350
TWh US
Solar
Wind
5. Electricity generation from intermittent renewables in the EU and the USA
Source: Eurostat and US DOE-EIA
TRANSFORMATION OF THE ELECTRICITY SECTOR
38 OXFORD ENERGY FORUM
I make a number of policy
recommendations. The ﬁrst is that EU
countries should be rethinking how best
to ﬁnance public policies, especially
in view of the Paris Agreement. It is
evident that in most countries, electricity
decarbonization is a necessary and
efﬁcient way of reducing carbon dioxide
emissions. This will involve additional
costs for society, at least initially. I think
it is a mistake to ﬁnance the additional
costs of decarbonization incurred in the
electricity sector almost entirely through
the electricity tariff, especially given the
distributional consequences.
Instead, I favour the introduction of a
rising minimum carbon tax on fossil fuels
speciﬁcally for those activities (such as
transport and heating) not covered by the
European Union Emission Trading
Scheme. This tax should also help to level
the competitive playing ﬁeld between
electricity and fossil fuels. The carbon tax
should be neutral from a ﬁscal perspective,
in the sense that there should be
corresponding reductions in other taxes,
with the aim of having a positive net
impact on the economy (in terms of, for
example, GDP, public debt, employment).
Second, for public policies that have
nothing to do with the efﬁcient and secure
supply of low-carbon electricity, I favour
recovering some of the related costs
through the general government budget
rather than through electricity tariffs.
This would have positive distributional
consequences since income tax is
progressive whereas high electricity
prices are a burden on the poorest
consumers. In principle, it also makes
sense for public policies that aim to meet
broad European or Spanish political
objectives (industrial, regional, or social)
to be ﬁnanced through the tax system
rather than through electricity tariffs.
Nevertheless, along with the carbon tax,
this sort of ﬁscal reform requires careful
study to ensure that the outcome is
optimal for the economy as whole.
‘TRANSPARENCY IS REQUIRED NOT ONLY
FOR FAIRNESS, BUT ALSO TO ENSURE A
LEVEL PLAYING FIELD IN THE EU…’
Third, in many EU countries, we need
greater transparency about which
costs are being collected through
the electricity tariffs, who is receiving
the beneﬁts (subsidies), and who is
bearing the burden. In some countries,
notably Germany, there is signiﬁcant
transparency. In others, notably Spain,
there is very little. Transparency is required
not only for fairness, but also to ensure a
level playing ﬁeld in the EU when it comes
to knowing whether state aid is being
granted to certain industrial consumers.
Fourth, with respect to tariffs, the
challenge is not simply to reduce the
level of ﬁnal prices, but to design an
efﬁcient network tariff structure to recover
recognized costs. Redesigning tariffs to
collect ﬁxed costs through a ﬁxed charge
may help to overcome the incentive
to bypass the system. However, the
higher the government wedge included
in the tariff (whether in the ﬁxed or
variable component), the harder it will
be to sustain these tariffs, politically and
economically, especially as the costs of
distributed generation fall.
Finally, whether public policy costs of
decarbonization are ﬁnanced through the
electricity tariff or through the budget, we
are left with the same underlying problem:
a growing tension between existing
electricity market design and the need to
decarbonize the economy. To date, this
has resulted in growing government
intervention that has distorted and
possibly broken electricity markets. It is
time to rethink the design of electricity
markets and their regulation, to be
consistent with decarbonization and with
increasing decentralization of energy
resources.
0.00
0.05
0.10
0.15
0.20
0.25
€/kWh Residential-EurostatDC
Commercial-EurostatIC Industrial-EurostatIF
Governmentwedge
Networks
Energyandsupply
6. Composition of average ﬁnal electricity prices in Spain for residential, commercial, and industrial
consumers in 2013-S2
Source: Eurostat and own calculations
FEBRUARY 2016: ISSUE 104
39OXFORD ENERGY FORUM
Introduction
Interest in demand response (DR
– sometimes referred to under the
more general heading of demand
side management, DSM) has been
growing worldwide and there are some
familiar examples in the OECD. For
instance, the USA has recently seen
a considerable growth in demand
response aggregators such as
ENERNOC, which manages around
25 GW of peak load DR capacity,
and the PJM (Pennsylvania–New
Jersey–Maryland) interconnection
in the north-east, which has well
developed DR markets. In the UK,
demand response has, for some time,
been an element of the National Grid’s
Short Term Operating Reserve and
the Grid has recently been developing
new instruments like the Demand
Side Balancing Reserve. The idea
underlying all these approaches is that
it is often better to deal with periods of
imbalance between electricity supply
and demand by adjusting demand
rather than generation. Supply and
demand have to be kept in balance
at all times because of the difﬁculty of
storing electricity; traditionally most
systems have relied almost exclusively
on ﬂexibility on the supply side (indeed
many still do). Including demand in
the calculations may not only be more
efﬁcient, it may also help to expand the
whole debate.
‘[CHINA] IS STARTING TO EXPERIMENT
WITH A MORE ECONOMIC APPROACH TO
DEMAND RESPONSE.’
While developments in the OECD are
familiar, it should not be forgotten that
there are also examples from outside
the OECD, in particular in China,
which is the focus of this article.
China has, in fact, practised a form of
administrative demand management
for some time. However, as it moves
towards the greater use of price
incentives within its electricity system,
it is starting to experiment with a more
economic approach to demand
response. In 2014, Shanghai was
selected by the National Development
and Reform Commission (NDRC) as
the ﬁrst pilot city in China to trial
municipality-led DR programmes.
The NDRC has also designated four
other municipalities (Beijing, Suzhou,
Tangshan, and Foshan) as DSM cities
and instructed them to undertake
DR pilots. As part of this process, the
OIES, working with the Environmental
Change Institute (ECI) of Oxford
University, undertook an assessment
of the Shanghai pilot on behalf of the
Natural Resources Defense Council
(NRDC – not to be confused with the
NDRC!). Their work (available on the
NRDC website as: ‘Assessment of
Demand Response Market Potential
and Beneﬁts in Shanghai’, dated
September 2015, and referred to in
this article as ‘the Report’) is designed
to provide an assessment of the
potential for, and beneﬁts of, demand
response in Shanghai, drawing both
on the outcome of the pilot and on
experience across the OECD. This
article summarizes the ﬁndings of
the Report.
Chinese context
In many ways, the factors driving
China’s interest in DR are the same as
elsewhere in the world, and reﬂect a
number of important trends, including
the following:
Increasing penetration of
intermittent generation and, as a
result, declining ﬂexibility on the
supply side. China, like many other
countries, has been investing heavily
in renewable sources and in
particular in wind power – wind
capacity has increased more than
300-fold since the beginning of this
century. The decreasing controllability
of the supply side, resulting from the
introduction of intermittent sources,
makes ﬂexibility on the demand side
more valuable.
Growth in demand side ﬂexibility.
With the development of smart grids
and smart meters (and localized
generation, which often acts
effectively as a demand-side
resource) the cost and practicality of
providing ﬂexibility on the demand
side is growing, and it is becoming
easier to coordinate large numbers
of distributed loads.
Liberalization of electricity
markets is also helping to
encourage more ﬂexible and
innovative approaches to pricing
and system management – system
operators are becoming more
open to the idea that not everything
has to be controlled from the
centre.
Finally, government policy is also
increasingly favourable to the idea of
demand response. Concerns about
climate change are leading to
increased emphasis on reducing
carbon emissions and encouraging
lower resource use – the power
station which remains unbuilt, and
the tonne of carbon not emitted, are
seen as valuable goals in
themselves.
However, it is also important to take
account of the very different design and
history of the Chinese electricity
system. In particular, it has in the past
put much less emphasis on economic
Assessment of demand response in Shanghai
Malcolm Keay, Xin Li, and David Robinson
TRANSFORMATION OF THE ELECTRICITY SECTOR
40 OXFORD ENERGY FORUM
incentives and price signals than is
seen in the OECD. Consumer prices
are regulated and do not necessarily
reﬂect the full cost of supply. System
operation is also generally on an
administrative basis rather than on the
sort of merit order we are familiar with
in the West – dispatch of power
stations takes place according to
generation plans which guarantee a
certain level of output for generators,
as a way of offering them a secure
income stream. Interregional and
interprovincial power exchanges also
normally take place according to a
ﬁxed schedule. To balance supply and
demand, utilities in China have
therefore operated administrative load
management programmes, including
load shifting and avoidance, and
restrictions on electricity use or
curtailments in the event of severe
power shortages. As a result of these
programmes, and of the importance of
industry in Chinese power demand, the
proﬁle of electricity demand in China is
very ﬂat by OECD standards.
(Shanghai is not entirely typical of the
Chinese system; it has a large
commercial and residential load, and
increasing air conditioning demand; it
operates a form of merit order based
on generation efﬁciencies; and it also
imports a signiﬁcant proportion of its
power from outside.)
‘TO BALANCE SUPPLY AND DEMAND,
UTILITIES IN CHINA HAVE THEREFORE
OPERATED ADMINISTRATIVE LOAD
MANAGEMENT PROGRAMMES…’
However, the Chinese electricity system
is changing. In particular, the authorities
are encouraging the use of more
market-based incentives, and the DR
experiments are part of this initiative
(see ‘Opinion on further Deepening the
Power Sector Reform’, a reform plan
issued by the State Council in March
2015). In accordance with this process,
voluntary interruptible contracts
between customers and utilities are
being developed. Electricity demand is
also changing as the balance of the
economy shifts from industrial
production to a greater share for
consumption and public services.
Also, given the growth of the air
conditioning load in cities such as
Shanghai, the ‘peakiness’ of electricity
demand is likely to increase; the DR
pilot is aimed, inter alia, at reducing the
need for new gas peaking plants.
Finally, China is, like other countries,
increasing its focus on environmental
issues: from local pollution (for
instance, coal-ﬁred power plants,
other than combined heat and power,
are not allowed in the eastern coastal
regions such as Shanghai) to global
climate change (China has a target
that carbon dioxide emissions should
peak by 2030 or earlier). The Shanghai
pilot was set up against this
background.
Potential
A number of factors have to be taken
into account in calculating the potential
of DR in Shanghai. In particular,
the Report considered two main
benchmarks:
Experience with the 2014 pilot.
The pilot was relatively limited in
scale. It involved 27 large commercial
customers who were asked to reduce
demand during peak periods (which
generally take place between 1 p.m.
and 3 p.m. on summer days,
because of the air conditioning load).
It achieved an overall reduction of 9
per cent in demand among these
customers, although individual
customers managed to reduce their
loads by much more signiﬁcant
amounts, while higher overall
reductions (up to 30 per cent) were
also achieved over short periods (up
to 15 minutes). Amongst other
things, the pilot was looking at the
potential for developing the role of
aggregators (on the same general
lines as in the USA).
International experience.
Experience in other countries
provides a general guide to the
potential, but clearly it cannot be
translated directly. Much depends
on the policy instruments used
(such as direct control of loads vs
price signals); the structure of
supply and demand in the systems
concerned; the nature of the market
involved; and the precise form of
demand response (such as whether
the service being provided is
short-term frequency control or a
wider contribution to reducing peak
capacity).
Taking account of these factors, and
of the policy instruments which might
be used in Shanghai, calculations
were made of the potential reduction in
peak capacity in the period up to 2030
under various scenarios. On a relatively
optimistic scenario, the analysis
showed that the market potential of DR
resources could reach 2.5 GW in 2030,
or about 4 per cent of peak demand
in that year, though more conservative
scenarios were also presented under
which the reductions could be less
– as little as 214 MW on the most
pessimistic forecast.
Beneﬁts
The beneﬁts of DR extend throughout
the electricity system – in principle, it
should reduce the need for new
generation capacity and, potentially,
for new transmission and distribution
capacity. It should also reduce the
need for generation from existing
facilities, together with the emissions
entailed. In addition, it may contribute
to a reduction in system balancing
costs and provide services such as
frequency response. Most of these
beneﬁts come in the form of avoided
costs – that is, they cannot be
observed directly but must be
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41OXFORD ENERGY FORUM
estimated. The costs of demand
response are also system and
customer speciﬁc and, especially
given the need to look into the future,
not calculable with complete
precision. Indeed, the Report focused
on avoided costs and did not assess
the costs of demand response.
Nonetheless, it attempted to produce
an indicative overall assessment of the
beneﬁts.
‘[DR] SHOULD REDUCE THE NEED FOR
NEW GENERATION CAPACITY AND,
POTENTIALLY, FOR NEW TRANSMISSION
AND DISTRIBUTION CAPACITY.’
The biggest single element is the
avoided generation capacity cost
(taken as gas-ﬁred plant, as required
by regulation in Shanghai). A
methodology often used in the OECD
to calculate the avoided capacity cost
is known as netCONE (CONE stands
for cost of new entry; netCONE is
based on annualizing the capital and
other upfront costs of a reference
plant, taken to be representative of new
plants on the system, and then taking
account of expected market revenues
to produce a net ﬁgure). The aim is to
calculate the annual capital costs of
new plants, which might be avoided
by DR programmes. There are many
estimates of such costs from OECD
sources – for instance, in the UK a
ﬁgure of 49 GBP/kW for netCONE was
calculated as part of the preparation
for the capacity auctions (though in
practice the outcome was much lower,
at less than 20 GBP/kW, partly because
of the number of existing plants which
were successful in the auction, partly
because of the number of diesel plants
involved – the reference plant for the
CONE calculations was gas-ﬁred).
As these complications suggest,
such calculations involve a number
of assumptions and can never be
deﬁnitive; furthermore, it is not easy
to translate the assumptions or
calculations directly from one system to
another. In addition, although there are
many estimates of construction costs
from OECD sources, construction costs
for new capacity in China tend to be
much lower, so in the ECI/OIES study,
estimates of Chinese costs were used
rather than OECD ones. The value of
the potential savings also depends to
a signiﬁcant extent on the discount rate
(for which various alternatives were
used for the purposes of the study)
though discounting is not common
practice in China. The study therefore
produced a range of possible ﬁgures
for the savings; beneﬁts from capacity
avoidance of around RMB550 million
in 2030 were possible on the more
optimistic scenarios.
The study also estimated other avoided
costs, including those of energy,
Total avoided costs
TRANSFORMATION OF THE ELECTRICITY SECTOR
42 OXFORD ENERGY FORUM
carbon dioxide, and transmission
and distribution, though these were
of a lesser order of magnitude. Total
avoided costs were estimated at a
little over RMB800 million in 2030
at a discount rate of 7 per cent on
the most optimistic scenario, with
correspondingly lower ﬁgures for the
pessimistic scenario (see the ﬁgure
‘Total avoided costs’). However the
study also warned that the ﬁgures
were only indicative and might in some
respects overstate the value of DR –
in particular because of the practice
of administrative demand planning,
which might have suppressed some
economic demand, leading to a lower
level of capacity than is economically
justiﬁed, and because the study
was also unable to include the costs
involved in DR.
Conclusions
Despite the various caveats noted
above, the study was particularly useful
as a ‘proof of concept’ in showing that
DR could, in principle, be a useful
policy tool in China, as in the OECD.
It included recommendations for the
design of DR policy instruments in
China and for further research to
develop a more robust evidence base
for calculation of the potential of DR.
Some of this work is now being
undertaken and it is likely that, as
elsewhere in the world, DR will
increasingly be an important part of
the electricity scene in China.
Power system reform to enable large-scale wind utilization in China
Zhang Xiliang and Xiong Weiming
Wind development and curtailment go
hand in hand
Recognizing that wind power is one
of the most mature, abundant, and
rich sources of renewable energy,
the Chinese government has made
considerable efforts to promote it for
the mitigation of carbon emissions and
improvement of environmental quality.
Over the last decade, China’s wind
industry has enjoyed dramatic growth,
overtaking the USA as the biggest wind
power market in 2010. By the end of
2014, China’s total wind power capacity
had reached 96.4 GW, accounting
for 7 per cent of the country’s total
generation capacity.
‘…CHINA’S WIND INDUSTRY HAS
ENJOYED DRAMATIC GROWTH,
OVERTAKING THE USA AS THE BIGGEST
WIND POWER MARKET IN 2010.’
Despite this successful increase in
wind capacity, however, since 2010
the industry has faced new challenges
due to its ineffective utilization. In the
ﬁrst half of 2015, wind curtailment
was as high as 17.5 TWh at national
level, meaning that 15.2 per cent of
technically available wind power could
not be connected to the electricity
grid, so the wind turbines had to shut
down. The problem of wind curtailment
is more prominent in the wind-rich
provinces. In Jilin, Gansu, and Xinjiang,
the proportion of curtailed wind power
generation in available wind output
has increased to 43 per cent, 31 per
cent, and 28 per cent respectively,
making a negative impact on ongoing
wind development. Although the
growth of wind installation is still on
the fast track, the ineffective utilization
of wind capacity has caused energy
waste, extra carbon emissions, and
lower incomes for wind farms; this
contradicts the original intention of
ensuring signiﬁcant priority to the
promotion of wind power in national
energy strategies. Hence, it is crucial
for the future development of wind
power in China to overcome wind
curtailment issues.
What led to wind curtailment?
In order to address this issue, a deep
analysis – to identify the obstacles
constraining the large-scale utilization
of wind power – is necessary. From
the technical perspective, curtailment
is caused by the intermittency and
volatility of wind power itself. However,
we argue that it is essentially due to
three main factors:
1 uncoordinated planning between
wind and grid,
2 inﬂexible dispatch mode, and
3 the lack of policy incentives for
stakeholders.
Firstly, inconsistency between wind
deployment and grid planning has
limited the transmission of wind power.
China’s rich wind energy resource
is mainly concentrated in the Three
North area (north-east, north-west,
and North China), which accounts for
approximately 90 per cent of national
wind potential. In order to achieve
large-scale development of the most
wind-rich areas, central government
has set the ambitious target of
achieving seven large-scale (10 GW)
wind farms by 2020, with six of them
being located in the Three North area.
By the end of 2014, the Three North
area accounted for more than 80 per
cent of China’s total wind installations
but its share of electricity consumption
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43OXFORD ENERGY FORUM
is only 34 per cent. The uncoordinated
distribution of wind capacity requires
the provision of electricity transmission
from wind-rich areas to load centres.
However, China’s grid planning has
enjoyed neither comprehensive
coordination nor a long-term prediction
of the rapid growth of wind energy.
As a consequence, not only has the
weakness of China’s transmission and
distribution infrastructure limited the
trade in wind power from large-scale
wind projects to the developed cities at
provincial level, but it has also created
barriers which affect wind power
connections to the transmission grid at
country level.
Secondly, current regulation modes
fail to take wind power integration into
consideration. Overall provincial yearly
dispatch planning is mainly based on
the balance in each province, while
inter-provincial trade is mainly for
grid-security reasons. As the
generation ﬂeet is still dominated by
coal-ﬁred power plants, the annual
minimum generation quotas are
allocated among coal-ﬁred units
through a highly political process, with
less consideration being given to wind
power generation at the beginning of
the year, when the long-term prediction
for wind energy is inaccurate.
Agreements relating to wind power are
overlooked in favour of the output of
coal-ﬁred power, as the annual
minimum quotas should be
guaranteed. In addition, a daily
dispatch plan is usually set by the
dispatching centre 24 hours ahead,
when the accuracy of wind prediction is
limited. That puts pressure on both the
dispatching centre and coal-ﬁred units
if there is a need to decrease planned
coal power output for the purpose of
wind integration.
Thirdly, current related policies,
especially feed-in tariffs, are
unfavourable for the promotion of
large-scale wind integration, as they
lack incentives for other stakeholders.
Currently, the feed-in tariffs for wind
power are divided into four ﬁxed
corresponding benchmarks according
to wind resources only:
0.47 RMB/kWh,
0.50 RMB/kWh,
0.54 RMB/kWh and
0.60 RMB/kWh.
The implementation of feed-in tariffs
for wind power has played a signiﬁcant
role in the development of wind energy,
with the guaranteeing of wind farm
investors’ income at the early stage
when wind generation only accounted
for a small share of electricity
consumption.
However, with the rapid growth of wind
installations, the inﬂexible pricing
mechanism has had a negative
impact, while beneﬁting other
stakeholders in the system, such as
electricity grid operators and coal-ﬁred
power. The completely ﬁxed tariff has
not enabled any further large-scale
expansion of wind energy utilization
since the implementation of thirdgeneration
technology in the wind
sector; wind power utilization lags
behind that of coal power and hydro
power.
From the perspective of wind power
transmission among provinces, as
the wind feed-in tariffs are higher than
the tariff for coal power, there is no
economic incentive for neighbouring
provinces, especially the load centre
provinces, to promote the large-scale
import of wind energy. Moreover,
the completely ﬁxed tariffs cannot
reﬂect the advantage of wind power
in terms of low marginal generation
cost. In wind-rich areas, the increasing
penetration of wind fails to reduce the
spot price of electricity through price
competition based on marginal cost,
so it is difﬁcult to ﬁnd the true value of
grid expansion and interconnection
utilization for other areas.
From the coal-ﬁred power perspective:
as integration of wind increases,
coal-ﬁred power generation declines.
With the absence of income transfer
mechanisms from wind power to coal
power, coal power units are likely to
submit undervalued down-regulation
ability to the dispatching centre to
avoid a sharp decline of their utilization.
Thus, for grid operators, the current
policy framework is unable to
incentivize the ﬂexible regulation of
coal-ﬁred plants. From the perspective
of the remaining participants in the
energy system, the ﬁxed pricing
policies on both the supply side and
the demand side do not enable
ﬂexibility in the existing system.
When wind energy is curtailed, ﬂexible
load (such as electric boilers and heat
pumps) can technically enable the
utilization of surplus electricity, but
the retail price cannot be reduced,
so this fails to release any ﬂexibility in
the system. Without suitable
compensation to ﬂexible generators
and consumers, the necessary
ﬂexibility for large-scale wind utilization
in the existing system is constrained
and future improvements to ﬂexibility
(such as storage technologies and
demand-side management) will not
attract the economic beneﬁts which
would allow technology and business
innovations.
As a conclusion, the current policy
framework, especially the ﬁxed feed-in
tariff, is the main obstacle constraining
the effective large-scale utilization of
wind power; consequently the system’s
ability to manage the uncertainty and
variability of wind energy is limited.
‘AGREEMENTS RELATING TO WIND
POWER ARE OVERLOOKED IN FAVOUR
OF THE OUTPUT OF COAL-FIRED
POWER…’
TRANSFORMATION OF THE ELECTRICITY SECTOR
44 OXFORD ENERGY FORUM
The failure of current government efforts to
address wind curtailment
In order to improve the utilization of
wind energy, the Chinese government
has taken a series of actions.
From 2013, the National Energy
Administration (NEA) has required
provincial governments and regional
grid companies to make wind
curtailment mitigation a priority in
wind development. And regional grid
companies must disclose the latest
information relating to wind utilization.
In addition, the importance of
development in southern and eastern
parts of China was mentioned in 2014;
this showed that future development
should consider not only the wind
resource but also the local electricity
consumption and grid structure.
‘FROM 2013, THE NEA HAS … MADE
WIND CURTAILMENT MITIGATION
A PRIORITY IN WIND
DEVELOPMENT.’
For grid construction, in 2015, the
Program for Strengthening the
Prevention and Control of Atmospheric
Pollution (issued by the NEA)
approved the construction of 12
ultra-high voltage (UHV) channels to
further expand the scale of the
transmission grid from north to south
and from west to east. The UHV
channels were expected to relieve the
bottleneck of wind exports from wind
farms to load centres. For localized
wind power utilization, demonstration
projects of wind heating are promoted
to deal with wind curtailment in
north-east China.
In early 2013, the NEA proposed a
plan supporting the replacement of
existing coal boilers with electric
boilers, by setting a speciﬁc electricity
price for each demonstration project,
in order to use surplus wind energy
for space heating during winter. For
wind power storage, the NEA has
made an announcement suggesting
the acceleration of pumped hydro
station construction, for the purpose
of providing potential regulation
capability for wind integration.
Government measures have aimed
at decreasing wind curtailment,
and it seemed as if their efforts had
seen some success in improving
wind utilization – from 2012 to 2014,
curtailments in wind power were:
20.8TWh, 16.2 TWh, and 14.1 TWh.
However, these improvements in
curtailment mitigation have been
limited, and in the ﬁrst six months of
2015 the wind curtailment was 17.5
TWh, which exceeded the annual
curtailment in 2013. Particularly in the
wind-rich provinces (such as Gansu)
the curtailment issue has deteriorated
rapidly, with more than 60 per cent of
wind output in some wind farms was
rejected by the grid in 2015.
Power system reform would bring new
opportunities to solve the problem
Wind power, as part of the electricity
system in China, is dominated by
the administrative planning policy
framework, which controls the quantity
and price of electricity tightly. In a
broad sense, China has succeeded
in expanding the generation and
transmission infrastructure needed to
support its economic growth. However,
the absence of market mechanisms
has caused a failure to drive the
electricity system onto a more efﬁcient
and green track.
To encourage efﬁcient market
competition, Beijing has ‘restarted the
engine’ for power sector development
by decoupling the transmission and
distribution tariffs from wholesale
prices, following a previous suspended
reform proposed in 2002.
In May 2015, the State Council released
Document 9, which issued the core
principle on further deepening the
reform of the power sector. The ﬁrst
task is to overhaul the role of grid
operators in the electricity market
and to set independent tariffs for
transmission and distribution, using
the method of ‘cost plus reasonable
proﬁts’. The core idea of the document
is to emphasize the role of market
mechanisms, injecting competition
into both the generation and retail
segments of the industry through the
operation of a modern and practical
electricity market. The other main
aspect of the reforms relates to
assisting efforts to integrate renewable
energy from the perspectives of power
sector decarbonization, air quality
improvement, and climate change
mitigation.
As mentioned above, the case of wind
curtailment demonstrates that
promoting the role of a market-based
policy framework in place of the
current administrative planning
structure is a vital approach for
large-scale wind utilization. Based on
the market and an incentive-based
framework, spot market competition
with ﬂexible pricing would bring
opportunities to solve the problem
which can hardly be met in a heavily
administrative planning system.
‘THE INTRODUCTION OF A SPOT
MARKET WOULD PROVIDE ESSENTIAL
PRICING SIGNALS FOR WIND ENERGY
TRADING.’
Firstly, the introduction of a spot
market would provide essential
pricing signals for wind energy trading.
In contrast to a ﬁxed feed-in tariff,
ﬂexible wind pricing based on marginal
cost can reﬂect the competitiveness of
wind generation that relates to low
variable operation cost. If wind energy
is able to decrease the spot electricity
price when wind resources are rich
(such as in winter), neighbouring areas
would then be willing to import
electricity from wind-rich areas; this is
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45OXFORD ENERGY FORUM
also preferable for wind power as it can
then sell it rather than curtail it. From
the long-term perspective, the
development of wind power would
have an impact on the spot market,
meaning that the concentration of
wind installations may increase the
price variation and decrease the
average electricity price. Hence, the
prospective wind investor would
reconsider the location of wind farms
according not only to the wind
resource itself but also to the
correlation between wind resource
and the local spot market prices. In
addition, the spot market price
differences between regions would
provide the true value for grid
expansion, which helps to optimize
the grid structure and motivate the
provision of transmission channels.
Secondly, the formulation of market
and incentive-based mechanisms
helps to remove reluctance on the
part of coal-ﬁred power plant and
grid operators. Currently, greater
utilization levels have not received a
welcome from coal-ﬁred power plant
and grid operators because there
is no reasonable compensation to
cover their extra costs. Large-scale
wind utilization would decrease the
generation quota for coal power and
attract extra costs when coal power
is needed to regulate for wind. With a
market-based framework, coal power
plants could get extra beneﬁts through
peak-regulation and security backup –
mechanisms whereby the income for
wind generators could more easily be
transferred to coal power plants. That
would also stimulate coal power plants
to improve the ﬂexibility performance
of their units, in order to provide more
ancillary services to the market.
Thirdly, market mechanisms
motivate the remaining stakeholders
to provide more ﬂexibility for largescale
integration. According to the
intermittency and volatility of wind
power, the peak–valley price difference
could be boosted. When wind
generation is high, combined heat and
power (CHP) plants could decrease
their power output and increase their
heat output, as the electricity price
would be cheap. When wind generation
is limited, CHP plants could increase
their output of power at the expense
of heat, while any remaining heating
demand is supplied by heat storage,
as the spot price is expected to
increase. Thus, CHP plants – formerly a
barrier to wind utilization in the heating
period – could now play a positive
role in ensuring wind utilization when
there is enough wind and sufﬁcient
production capacity when there is no
wind. Similarly, other stakeholders like
demand-side management, storage
technologies, and electric vehicles
could also contribute to the balance of
the electricity system.
In sum, the market-based framework
proposed in Document 9 has the
potential to improve wind integration
signiﬁcantly, on the basis of both a
broad spot market and a ﬂexible pricing
system for all the generators.
In the existing game, grid operators,
coal-ﬁred power, and wind power were
all losing players without the incentive
to decrease wind curtailment. With
the ongoing power reform, it could be
seen that the construction of a modern
electricity market would promote
coordination between wind energy and
the rest of the energy system, which is
the long-term key to the realization of
large-scale wind utilization.
The task of the reform is to ﬁnd the
new equilibrium point for all the players.
However, the capital cost of wind
power is expected to be higher than
that of coal power for the foreseeable
future and protection for wind investors
is therefore required to avoid market
price drops and wind-limited periods.
To set suitable ﬂexible prices for wind
power, a combination of feed-in tariff
and market price is suggested here, in
which the actual return of wind energy
is divided into two parts: the ﬁxed wind
energy subsidy and the market price.
The feed-in tariff (the successful policy
instrument for wind promotion) should
be replaced by a feed-in premium
(market price plus ﬁxed wind tariff) or
by another ﬂexible pricing system
which combines the market price
signal and subsidy.
‘THE MARKET-BASED FRAMEWORK
PROPOSED IN DOCUMENT 9 HAS
THE POTENTIAL TO IMPROVE WIND
INTEGRATION SIGNIFICANTLY. . .’
TRANSFORMATION OF THE ELECTRICITY SECTOR
46 OXFORD ENERGY FORUM
Christoph Burger is a faculty
member at the European School
of Management and Technology
(ESMT), Berlin
Scott Burger is a doctoral student at
the MIT Institute for Data, Systems
and Society
Rolando Fuentes is Research Fellow,
King Abdullah Petroleum Studies and
Research Center (KAPSARC), Riyadh
Iván Mario Giraldo is Economist,
Senior Associate (Latin America) at
Market Analysis Ltd
Richard Green is Professor of
Sustainable Energy Business at the
Business School, Imperial College,
London
David Harbord is Director at Market
Analysis Ltd
Tooraj Jamasb is Chair in Energy
Economics at Durham University
Business School, Durham
Malcolm Keay is a senior research
fellow at the Oxford Institute for
Energy Studies
Rabindra Nepal is a lecturer in
Economics at CDU Business School,
Charles Darwin University, Darwin,
Australia
David M. Newbery is Director of the
Energy Policy Research Group at
Cambridge University
Ignacio Pérez-Arriaga is Visiting
Professor at the Sloan School of
Management (MIT) and Professor
at Comillas University and the
European University Institute in
Florence
Rahmat Poudineh is lead research
fellow for the electricity programme,
Oxford Institute for Energy Studies,
Oxford
David Robinson is a senior research
fellow at the Oxford Institute for
Energy Studies and President, David
Robinson & Associates
Fereidoon P. Sioshansi is President of
Menlo Energy Economics, California
Goran Strbac is Chair in Electrical
Energy Systems at the Department of
Electrical and Electronic Engineering,
Imperial College, London
Graham Weale is Chief Economist at
RWE AG, Essen
Jens Weinmann is Programme
Director at the European School
of Management and Technology
(ESMT), Berlin
Xin Li is a research fellow at the
Oxford Institute for Energy Studies
Xiong Weiming is a doctoral student at
the Institute of Energy, Environment
and Economy, Tsinghua University
Zhang Xiliang is Professor of Energy
Economics and Policy at the
Institute of Energy, Environment and
Economy, Tsinghua University
The views expressed in this issue are
solely those of the authors and do
not necessarily represent the views
of OIES, its members, or any other
organization or company.
CONTRIBUTORS TO THIS ISSUE
FEBRUARY 2016: ISSUE 104
47OXFORD ENERGY FORUM
EDITOR: Bassam Fattouh
CO-EDITORS: Rahmat Poudineh, David Robinson, and Malcolm Keay
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Recently published book
Europe’s Long Energy Journey –
Towards an Energy Union
by David Buchan and Malcolm Keay
February 2016
Recent Research Papers
Under the Mountains – Kurdish Oil
and Regional Politics
by Robin Mills
January 2016
Electricity Markets are Broken – Can
they be Fixed?
by Malcolm Keay
January 2016
Fiscal Stabilization in Oil and
Gas Contracts – Evidence and
Implications
by Mario Mansour and Carole Nakhle
January 2016
The Evolution of European Traded
Gas Hubs
Patrick Heather
December 2015
Incidence and Impact – A
Disaggregated Poverty Analysis of
Fossil Fuel Subsidy Reform
by Jun Rentschler
December 2015
Reforming Electricity Reforms? Empirical
Evidence from Asian Economies
by Anupama Sen, Rabrindra Nepal, and
Tooraj Jamasb
February 2016
Natural Gas in China – A Regional
Analysis
by Xin Li
November 2015
A Holistic Framework for the Study of
Interdependence Between Electricity
and Gas Sectors
by Donna Peng and Rahmat Poudineh
November 2015
US Shale Oil Dynamics in a Low Price
Environment
by Trisha Curtis
November 2015
Oil in Uganda – Hard Bargaining and
Complex Politics in East Africa
by Luke Patey
October 2015
The Dynamics of the Revenue
Maximization – Market Share Tradeoff:
Saudi Arabia’s Oil Policy in the
2014–2015 Price Fall
by Bassam Fattouh, Rahmat Poudineh,
and Anupama Sen
October 2015
NEW OIES PUBLICATIONS
Recent Energy Comments
Gazprom – Is 2016 the Year for
a Change of Pricing Strategy in
Europe?
by James Henderson
January 2016
Has the North Sea Entered a Late-life
Crisis?
by Virendra Chauhan, Maarten van
Mourik, and Amrita Sen
December 2015
The New Economics of Oil
by Spencer Dale
October 2015
TRANSFORMATION OF THE ELECTRICITY SECTOR
48 OXFORD ENERGY FORUM