Report

Rethinking power
markets: capacity
mechanisms anddecarbonisation
Laurie van der Burg and Shelagh Whitley
May 2016

Overseas Development Institute203 Blackfriars Road
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© Overseas Development Institute 2016. This work is licensed under a Creative Commons Attribution-NonCommercial Licence (CC BY-NC 4.0).

Cover photo: Michael Murphy (2010). Looking down from the 14th floor of the London Transport HQ at their recently installed solar power panels on the10th floor.

Contents
Acknowledgements

5

Glossary

5

Acronyms 

8Executive summary9Introduction

11

1. Electricity markets in transition

12

1.1 Renewables on the rise

12

1.2 Loss of flexible capacity

15
16

2. Capacity mechanisms: rationale, types and current demands
2.1 The historic rationale for introducing capacity mechanisms

16

2.2 Types of capacity mechanisms

17

2.3 A new security of supply challenge 

18

3. Beyond capacity mechanisms: options to integrate increasing shares of renewable electricity 20

3.1 Improving system and market operations20

3.2 Adding flexibility to the system

22

4. Designing and implementing capacity mechanisms – risks to wider energy policy objectives

24

4.1 Political risks

24

4.2 Technical risks 26

4.3 Institutional risks

33

5 Recommendations for supporting power market reforms and climate and clean energy objectives

35

5.1 Assessing and understanding security of supply issues

35

5.2 Identifying options to improve existing market design 36

5.3 The careful design and implementation of capacity mechanisms

36

Annex 1: Interviewees

38

References

39

Rethinking power markets: capacity mechanisms and decarbonisation 3  

List of tables, figures and boxes
FiguresFigure 1: A traditional, centralised power system and a future, lower-carbon, decentralised power system

13

Figure 2: Gross electricity generation by fuel in GWh

14

Figure 3: Types of capacity mechanisms

18

Figure 4: Estimated power demand over a week in 2012 and 2020, Germany

19

Figure 5: Different building blocks of electricity markets

21

Boxes
Box 1: A brief introduction to electricity markets

21

Box 2: A patchwork of capacity mechanisms – undermining EU regional efforts on security of supply?

25

Box 3: United States: adapting to new market realities

28

Box 4: The UK capacity auctions – subsidising new dirty power generation and undermining flexibility

29

Box 5: France: incentivising demand side response?

31

Box 6: Germany’s proposed system-wide approach32

4

ODI ReportAcknowledgements
This paper was written by Laurie van der Burg and Shelagh
Whitley from ODI. The authors would like to thank thereports’ peer reviewers, who dedicated considerable time toproviding extensive and insightful comments on the study’s
drafts: Dave Jones (Sandbag); Matthew Wittenstein (IEA);
Andrew Prag (OECD); Andrew Scott (ODI); James Rydge(NCE); Anne-Sophie Chamoy (Energy Pool); Byron Orme
(IPPR); and Anna Locke (ODI).
Readers are encouraged to reproduce material from thisreport for their own publications, as long as they are notbeing sold commercially. As copyright holder, ODI requests
due acknowledgement and a copy of the publication. For
online use, we ask readers to link to the original resourceon the ODI website. This and other CEP reports areavailable from www.odi.org/climate-environment. The
opinions expressed herein are the authors’ and do notnecessarily reflect those of ODI. © Overseas Development
Institute 2016. Creative Commons CC BY-NC 4.0

Glossary
Ancillary services: A range of services that System
Operators (SOs) procure to respond to unexpected
shocks, such as the sudden shutdown of a power plant,
to guarantee system security in real-time. These include
black-start capability (the ability to restart a grid following
a blackout); frequency response (to maintain systemfrequency with automatic and very fast responses); fast
reserve (which can provide additional energy whenneeded); the provision of reactive power and various otherservices (ENTSO-E, 2016).
Balancing markets: These operate after trading in thewholesale electricity market ends (after gate closure). In
the balancing market, system operators manage a numberof ancillary services to balance supply and demand in andnear-real time (ENSTO-E, 2016).
Baseload, mid-merit, and peak-load generation:
Different operation modes of generating plants based on a
combination of technical and commercial factors (e.g., howeconomically the plant can run at different load factors). A
power plant that runs all or most hours to meet minimum
electricity needs is referred to as ‘baseload’. An operationthat runs for short periods during times of high demandor resource scarcity is referred to as ‘peak load’, and an
operation between baseload and peak that is adjusted
to respond to fluctuating demand throughout the day isreferred to as ‘mid-merit’ (Gottstein and Skillings, 2012).
Capacity: The maximum power that is available fromthe power sector or a power station at any point in time
(NIC, 2016). Power stations do not operate at full capacity
at all times, therefore generation is not the same as capacity.
Capacity mechanisms (CM): A mechanism that rewards
market participants for available capacity, on top ofrevenues generated by selling electricity in the wholesalemarket. These payments are meant to ensure securityof supply by incentivising sufficient investment in new
capacity or preventing the retirement of existing capacity.

CMs take many forms and are sometimes referred to as
capacity remuneration mechanisms (CRMs).
Demand response aggregators: Third party
intermediaries or suppliers that reduce or shift demand on
behalf of consumers in return for a compensatory payment,
and that sell aggregated demand response products on thewholesale electricity market.
Demand-side response (DSR): The intentional
modification of electricity usage during system imbalances
or in response to market prices (Hurley et al., 2013).
Currently, demand side response consists mostly ofindustrial users that withdraw, lower or shift theirdemand when there is limited supply, or that allow system
operators or third-party aggregators to do so in return for
a compensatory payment. In addition, new products are
increasingly available that enable households to reduceor shift their electricity consumption in response to pricesignals (OECD, 2015).
Dispatchable generation: Sources of electricity that canincrease or decrease output on command. These includehydroelectricity, gas-fired and biomass power and somecoal-fired generation. Some types of base load generation,such as nuclear power, cannot easily adjust output, andwind and solar power are also less controllable because of
their variability.
Energy-only markets: These have no explicit mechanism
for procuring or paying for capacity. Revenues are earned
primarily by selling electricity on the wholesale electricity
market (Hogan, 2012).
Flexibility: The ability to modify supply and demand to
the needs of the electricity system within a given timeframe.
Gate closure: The moment when trading on thewholesale electricity market ends and the system operator
takes on the role of ensuring a balance between demandand supply near or in real time in the balancing market(Keay-Bright, 2013).

Rethinking power markets: capacity mechanisms and decarbonisation 5  Interconnectors: Electricity cables that facilitate thephysical linking of electricity systems, allowing electricity
to flow across borders and sub-national electricity markets.
This enables the exporting of electricity when supply isabundant, and the importing of electricity in times ofsystem stress (Ofgem, 2016).
Load factor: A measure of the average output of power
stations relative to their installed capacity and, therefore,
an indicator of capacity utilisation. It is expressed in theratio of kilowatt-hours (kWh) produced in a given period,
divided by the total possible kWh that could have been
produced over the period.
Loss of load expectation (LOLE): LOLE represents thenumber of hours or days per year in which it is estimatedthat supply will not meet demand.
Merit-order principle: In wholesale electricity markets,bids for electricity generation are ranked (or ordered) fromthe lowest cost to the highest cost. Based on this ranking,electricity generation available at the lowest price isdeployed first to meet demand needs.
Missing money problem: In energy-only markets, where
market operators earn revenues primarily by selling electricity
in the wholesale electricity market, government regulation ormarket failures may prevent prices from rising to sufficiently
high levels (and frequently enough) for mid-merit andpeaking plants to recover their fixed costs. Typically, thisprovides the rationale for the introduction of CMs.
Mothballing: The preservation of an electricity
production facility, which remains idle. In other words,
power plants are turned off but kept in working order sothat production can be restored if needed.
Non-dispatchable generation: Energy sources that cannot
or can only limitedly be controlled in response to demand
fluctuations or supply interruptions. This includes nuclear,run-of-river hydroelectric plants, solar, wave and wind power.
Operating reliability: The ability of the electricity system toensure short-term power system reliability and to withstandunanticipated disturbances or imbalances. Balancing andancillary services contribute to operating reliability. A reliable
power system requires both resource adequacy and operating
reliability (Keay-Bright, 2013; NERC, 2013).
Power system reliability: A power system is reliable
when it has both adequate resources to meet the highest
levels of electricity consumption (resource adequacy) and isable to balance demand and supply in real-time, including
in response to unexpected outages (operational quality).
Providers of capacity: Electricity market participantsthat either provide generating capacity or reduce electricity
demand in response to supply shortages. Examples include
owners of generation capacity, demand side response
aggregators, consumers that actively manage their demand,interconnection, and storage.
Ramping: Ability of an energy resource (generation or
demand) to change its power output or consumption up or
down. The ramp rate is the speed of output/consumptionchange measured in MW per minute (Keay-Bright, 2013).

6

ODI Report

Reliability standard: In some countries the regulatoror system operator sets a performance standard for the
power system. Different metrics are used. Some European
countries, for example, use a Loss of Load Expectation(LOLE) reliability standard, defined as the average numberof hours a year for which it is estimated that supply will
not meet demand (Keay-Bright, 2013).
Resource adequacy: The availability of sufficient
generating and demand side capacity to ensure that
forecasted electricity needs can be met.
Scarcity prices: High wholesale electricity prices that
occur when electricity demand is high or when there is
an imbalance between electricity demand and supply
that leads to the deployment of higher-cost technologies.
Scarcity prices allow providers of peaking capacity torecover their fixed costs and provide price signals forinvestments in new electricity generation or demand-side
capacity when this is needed. In some countries, price caps
prevent scarcity prices.
Scarcity value: The value of uninterrupted service toconsumers often expressed as Value of Loss Load (VOLL)(Baker and Gottstein, 2013).
Security of Electricity Supply: the ability of the electrical
power system to provide electricity to end-users with a
specified level of continuity and quality in a sustainable
manner (Eurelectric, 2006).
Smart technologies: Appliances and technologythat automatically control the use of energy – often
remotely (NIC, 2016).
Storage: A wide range of technologies that can store
electricity and can act as sources of demand at times oflow demand and sources of supply when demand increases
or when other sources reduce output (World Bank, 2015).
While some storage technologies will store energy forminutes or hours, others can store electricity from night
to day or across seasons. Examples include hydroelectric
pumped storage, compressed air, water heaters, flywheels,
the transformation of excess electricity into hydrogen,storage in the form of molten salts in concentrated solarpower plants and different battery technologies (flow,
lead-acid, lithium-ion, sodium and zinc batteries).
Stranded assets: Assets that lose value or turn into
liabilities before the end of their economic life. This canbe caused by a number of risks, including technologicalinnovation and market developments, but also climate andenergy policy and regulation (adapted from HSBC, 2015).
Examples of potential risks to the value of conventional
electricity generation assets include competition fromnew technologies (such as renewable energy technologies
or storage), falling demand for electricity or emission
reduction policies.
Suppliers: Suppliers buy electricity from generators orin the wholesale electricity market and then sell it to firms
and households in the retail market (NIC, 2016).

System peak: The highest level of total energy demand on
the power system at a given time (e.g. daily peak, seasonalpeak, annual peak) (Keay-Bright, 2013; NIC, 2016).
Transmission network: The high voltage network that isused to move electricity long distances (NIC, 2016).
Transmission System Operators (TSOs): These areresponsible for balancing supply and demand in theelectricity system on a second-by-second basis, which
ensures grid stability. TSOs are tasked with the operationof the electricity system after gate closure by dispatching
power plants and demand response on the basis of bids inthe wholesale electricity market. They are also responsible
for balancing capacity in the case of system stress caused
by unexpected weather conditions, technical deficiencies or
short-term changes in electricity demand (Grigorjeva, 2015).
The TSO in the UK is National Grid, in France the TSO is
Réseau de Transport d’Électricité (RTE), while Germany has
multiple TSOs. In the US they are often called Independent
System Operators or Regional System Operators.
Value of lost load (VOLL): The estimated maximum
price that customers would be willing to pay to avoid aloss of supply. The value of VOLL is often different foreach class of consumer (industrial, commercial, domestic)
and for individual consumers within those broad classes(Baker et al., 2015; IEA, 2016).
Variable generation: The term variable describes thefluctuating nature of wind and solar electricity generationin response to changing weather conditions, independentlyof changes in demand. This makes these sources lesscontrollable for network operators than dispatchable
resources (such as hydropower, gas-fired generation or
demand side response), for which output can be increased
or decreased in response to supply scarcity or fluctuations
in demand (Hogan, 2012).
Wholesale electricity market: The market wheretrading takes place between generators, retailers and otherfinancial intermediaries for delivery of electricity to meet
forecasted demand before gate closure. After gate closure,system operators are responsible for balancing supply anddemand in real-time (see balancing markets).

Rethinking power markets: capacity mechanisms and decarbonisation 7  Acronyms
ACER

Agency for the Cooperation of Energy Regulators

KWh

Kilowatt hour

CEER

Council of European Energy Regulators

LOLE

Loss of Load Expectancy

CCGT

Combined Cycle Gas Turbine

LOLP

Loss of Load Probability

CM

Capacity mechanism

MW

Megawatt

CRM

Capacity Remuneration Mechanism

MWh

Megawatt hour

DG

Directorate General

NEM

EC

European Commission

National Electricity Market, wholesale electricity market
for eastern Australia

EDF

Électricité de France S.A.

NERC

North American Electric Reliability Corporation

ENEL

originally Italy’s National Entity for Electricity (Entenazionale per l’energia elettrica)

NIC

National Infrastructure Commission		

NY-ISONew York Independent System Operator

ENTSO-E European Network of Transmission System Operators
for Electricity

OCGT

Open Cycle Gas Turbine

OFGEM

Office of Gas and Electricity Markets

E.ON

PJM

Pennsylvania-New Jersey-Maryland Interconnection

RTE

Réseau de Transport d’Électricité

RWE

until 1990: Rheinisch-Westfälisches Elektrizitätswerk AG

SO

System operator

STOR

Short Term Operating Reserve

SBR

Supplemental Balancing Reserve

TFEU

Treaty on the Functioning of the European Union

TSO

Transmission System Operator

VOLL

Volume of Loss Load

European holding company based in Düsseldorf,
Germany, running one of the world’s largest investorowned electric utility service providers

ERCOT

Electric Reliability Council of Texas

EU

European Union

EU ETS

European Union Emission Trading Scheme

Eurelectric Union of the Electricity Industry in Europe
GDF Suez Now ENGIE
GHG

Greenhouse gas emission

IEA

International Energy Agency

IEM

Internal Energy Market

8

ODI Report

Executive summary
Context and aims
With variable wind and solar power generation accounting
for a growing share of electricity generation, powersystems are undergoing significant transformation. For
governments, this raises new concerns about security ofelectricity supply when the sun does not shine or the wind
does not blow, or, conversely, when there is high renewableelectricity supply, but insufficient demand to match it.
At the same time, the growth in renewable electricity
generation, combined with falling demand among otherfactors, has led to a loss of flexible power generation
capacity (in particular gas). Accordingly, the power system
is losing capacity that can be adjusted in response tofluctuations in supply at a time when increased flexibility isnecessary to complement an increasing share of renewables.
This has raised concerns about security of supply andhas re-ignited interest in capacity mechanisms (CMs)across the European Union (EU) and beyond. CMs comein many different forms, and are generally designed tooffer payments to electricity market operators for theircapacity to produce electricity or to reduce or shiftelectricity demand. By providing a stable stream ofrevenue, independently of actual electricity produced andsold, capacity mechanisms aim to prevent the shutdownof existing generation capacity or incentivise investment
in new resources, with the primary objective of ensuring
security of electricity supply.
With a particular focus on the EU, this report is directed
at those who want to advance climate objectives, but who,
until now, have had a limited understanding of power
markets. It provides guidance on how governments could
assess and ensure security of supply while meeting parallel
objectives, including decarbonisation and the phase outof fossil fuel subsidies. As a number of EU member states
are moving ahead with the design and implementation ofdomestic CMs the European Commission has launched aninvestigation into these developments. Its findings will feed
into its electricity market redesign proposals for the endof 2016. This is therefore a key moment to influence thisprocess, as well as the wide range of power market reforms
planned at the national and sub-national level.

Capacity mechanisms – risks to wider energy
objectives
In a context of growing needs for flexibility to respondto fluctuations in wind and solar generation and to meet
decarbonisation objectives, the traditional ‘generation
adequacy’ approach to CM design is no longer suited
to address today’s challenges. Traditional capacity
mechanisms have failed to adequately value flexibility andcarbon intensity.

Recent experiences with the development andimplementation of CMs in France, Germany, the UK and
the US have flagged these challenges, as well as options for
improving capacity mechanisms:•• The UK’s capacity auction has led to large payments –estimated at £658 million ($966 million) – to the mostpolluting forms of electricity generation, including
diesel- and coal-fired power.
•• Germany is making efforts to improve electricity market
operations to promote flexibility and facilitate theuptake of variable renewables, but has also proposeda new capacity reserve that is made up entirely ofhigh-carbon lignite-fired power plants. Our analysis
suggests that this reserve, with an estimated cost to
the government of €1.6 billion ($1.7 billion), may be
a political compromise around the closure of theseold power stations, rather than a measure to support
security of supply or reduce emissions.
•• Although a proposed French CM has the stated objectiveof promoting demand response and flexibility, highlevels of market concentration (by state-owned utility
EDF) and scheme complexity may create barriers to newmarket entrants in the clean energy space. It remains tobe seen whether the mechanism will be introduced asplanned, as the European Commission has launched anin-depth investigation into its planned design.
•• The limitations of CMs that remunerate generation
capacity regardless of flexibility became apparent ina number of US power markets. In response, PJM(Pennsylvania-New Jersey-Maryland Interconnection)
has gradually promoted the participation of demandside response in its capacity market. This, alongsideother measures, has helped reduce the costs of ensuring
the reliability of the power system by an estimated 1020% in 2014/15, delivering estimated consumer costsavings of $1.2 billion.
Overall, our review of current and planned CMs in
the EU and US suggests that capacity mechanisms risk
undermining parallel energy and climate objectives bylocking in dependence on high-carbon power generation
assets. The introduction of CMs is often politicallymotivated, instead of based on a rigorous analysis of
their need. In addition, challenges with their design andimplementation means that there is a serious risk thatthey undermine governments’ parallel objectives of
ensuring system reliability and decarbonisation. Finally,
the uncoordinated introduction of CMs risks undermining
wider efforts to integrate energy markets, which,

Rethinking power markets: capacity mechanisms and decarbonisation 9  paradoxically, are meant to ensure a more efficient use ofresources and improve security of supply.

should take a system-wide approach that supports rather thanundermines decarbonisation. This includes:

Recommendations•• establishing a clear understanding of the scale and the natureof the reliability challenges facing their power systems•• considering whether improvements in current market
design can help to improve power system reliability•• recognising the potential of demand side response,interconnection and storage in providing economicallycompetitive, low-carbon flexibility.

Given the urgent need to move towards zero-carbon powersystems, governments must be held to account for meeting
parallel objectives of decarbonisation when they seek to address
issues around power system reliability. Instead of focusing
narrowly on CMs as a near-term solution, governments

10

ODI ReportIntroduction
With variable renewable energy capacity accounting
for an increasing share of electricity generation, powersystems are undergoing significant transformation. For
governments, this raises new concerns about security ofelectricity supply when the sun does not shine or the wind
does not blow, or, conversely, when there is high renewableelectricity supply, but insufficient demand to match it.
This has re-ignited interest in capacity mechanisms(CMs) across the European Union (EU) and beyond. CMs
take many different forms but are generally designed
to offer payments to capacity providers to prevent the
shutdown of existing generation capacity or incentivise
investment in new resources, with the primary objective ofensuring security of electricity supply. These payments aremeant to ensure that enough resources are kept available
for matching demand and supply, in periods of both highand low levels of renewable electricity generation.
Although there is growing interest in CMs, they are
not a new tool. Since the liberalisation of electricity
markets began in the early 1980s, governments worldwide
have used various approaches, including CMs, to enablegenerators that only operate at times of peak-demand to
recover their fixed costs. Given this history, experienceswith CMs and wider power market reforms, both within
and beyond the EU, can provide lessons for those who
aim to support the security of electricity supply in a waythat is consistent with decarbonisation. At the same time,
the fundamental transformations that are taking place inelectricity markets, linked in part to decarbonisation, makeit essential to reconsider traditional approaches to securityof supply and capacity mechanisms.
This report, with its particular focus on the EU, is
directed at those who are seeking to advance climate
objectives, but who, until now, have had a limited
understanding of power markets. It provides guidanceon how governments could assess and ensure securityof supply while meeting the parallel objectives ofdecarbonisation and the phase out of fossil-fuel subsidies.
It also highlights the role of both market redesign and theopportunities provided by new technologies and energy
services in the development of secure, affordable, andefficient power systems.
The report is structured as follows. Section 1 outlines
the rapid shifts in electricity markets and how these are
creating new concerns about security of supply. Section 2
discusses why governments deploy CMs and their various
types. Section 3 reviews the opportunities for market
redesign and for additional flexibility to create low-carbon,
secure power systems. Section 4 assesses the risks thatCMs may pose to the achievement of wider government
objectives (including decarbonisation). Finally, Section 5
provides an overview of lessons learned and implications
for assessing and addressing security of supply concerns ina manner that is consistent with wider climate and energy
objectives. This report is based on a review of recent
literature and a number of interviews (see Annex 1).

Rethinking power markets: capacity mechanisms and decarbonisation 11  

1. Electricity markets intransition
Electricity markets across the European Union, as in otherregions around the world, are going through significant
transformation, leading to increased concerns about
security of electricity supply. We are seeing a rapid increasein the share of renewable, often decentralised electricity
production, driven by decarbonisation objectives andpolicies and a sharp reduction in the cost of renewableenergy technologies (FS-UNEP, 2016). At the same time,
there is a decline in conventional, centralised and often
more flexible generation capacity. Another factor that iscontributing to the shifting landscape of electricity markets
is the availability of innovative, low-carbon solutions tobalance demand and supply (discussed in section 3 of thisreport) (Figure 1 provides an illustration of the changing
landscape of power systems).

1.1 Renewables on the rise
With the recent adoption of the Paris Agreement, world
leaders reaffirmed their commitment to limit the increasein global average temperature to well below 2°C degrees,
and agreed to pursue efforts to limit global temperaturerise to an even more ambitious 1.5°C target (UNFCCC,2015). The Agreement calls for a peak in greenhouse gas(GHG) emissions as soon as possible, followed by rapid
reductions. As energy supply remains the biggest source of
GHG emissions, an urgent shift from high- to low-carbon
energy is imperative (IPCC, 2014). The power sector willplay a central role in the transition to low-carbon energy
systems as low-carbon electricity can substitute for fossil
fuels in transport and heating (OECD, 2015).
The EU has adopted various policy packages since 1997 topromote the uptake of renewables with the objectives of reducing
Europe’s reliance on energy imports and its GHG emissions.
•• The EU Emissions Trading Scheme (EU ETS), presented
as the ‘cornerstone’ of EU climate change policy, waslaunched in 2005 (Directive 2003/87/EC). However,
because of a surplus of emission allowances, it hascreated a very low carbon price that does not provide
sufficient incentives for the reduction of emissions.
Despite a number of initiatives to improve its
functioning, prices are projected to remain low through2030 (Buck et al., 2015).

12

ODI Report•• The EU’s 2020 climate and energy package sets abinding region-wide target of 20% renewables infinal energy consumption by 2020 and the objectiveof reducing energy consumption by 20% by 2020
(Directive 2009/28/EC; Directive 2012/27/EU).
•• The longer-term 2030 Energy Strategy sets targets ofa 40% reduction in GHG emissions on 1990 levels, a
27% share of renewables in energy consumption, and a
27% reduction in energy consumption by end-users by
2030 (European Council, 2014).
•• As a member of the G20, the EU committed to phasingout ‘inefficient fossil fuel subsidies’ in 2009, recognisingthat these encourage wasteful consumption andundermine investments in clean energy (G20, 2009).
The European Commission has repeatedly called upon
Member States to phase out environmentally harmful
subsidies by 2020, including those for fossil fuels(European Commission, 2011a).
As a result of policies adopted to achieve renewable energy
targets and a rapid decline in the costs of renewableenergy technologies, the EU has seen a significant increasein the share of renewables in the power mix (Figure 2),particularly in variable wind and solar electricity generation(FS-UNEP, 2016). In 2014, renewables accounted for one
third of electricity production across the EU, up from 13%
in 1990, with large variations between Member States(Eurostat, 2015a). While hydropower still accounts for thelargest share of renewable electricity production, its sharehas declined sharply from 94% in 1990 to 45% in 2013 –a fall linked to the rapid growth in biomass and in variablewind and solar power (Eurostat, 2015b).
Between 2005 and 2014, wind power generation morethan tripled and solar electricity generation grew by afactor of 40 (Eurostat, 2015b). Variable renewable energy
sources already make up a significant share of electricity
production in some Member States. In Spain, for example,
renewables met 42% of electricity demand in 2014. On
one day in July 2015, unusually high winds enabled
Denmark to meet all of its electricity needs with wind,while exporting excess capacity to Norway, Germany andSweden, with Norway storing a portion of this supply in its
hydropower systems for later use (Neslen, 2015).
For the EU to achieve its target of an 80-95% reduction
in GHG emissions by 2050, the power sector will need

Figure 1: A traditional, centralised power system and a future, lower-carbon, decentralised power system

TRADITIONAL POWER SYSTEM
GENERATION

TRANSMISSION

Power Station

Power Transformer

Transmission substation

DISTRIBUTIONCOMMERCIAL AND
INDUSTRIAL BUSINESSCONSUMERSDistribution
substation

RESIDENTIAL
CONSUMERSDISTRIBUTION
AUTOMATION
DEVICES

FUTURE POWER SYSTEM
Solar PV power plant

GENERATIONWind power plant

Storage

Solar PV power plant

TRANSMISSION

Power Station

Power Transformer

Transmission substation

DISTRIBUTIONCOMMERCIAL AND
INDUSTRIAL BUSINESSCONSUMERSDistribution
substation
Solar PV
power plant

Storage

RESIDENTIAL
CONSUMERSDISTRIBUTION
AUTOMATION
DEVICES

StorageWind power plant

Source: NIC (2016).

Rethinking power markets: capacity mechanisms and decarbonisation 13  

to reach full decarbonisation (Hewicker et al., 2011;
European Commission, 2011b). At the same time,electrification of road transport will be necessary to meet
decarbonisation objectives, and this will increase electricity
demand in the transport sector in the EU by a factor ofeight compared to 2005 (ECFIN, 2015). Considering thecurrent availability of renewable energy sources in the EU,
this will require a significant further increase in variablewind and solar generation (Gottstein and Skillings, 2012).
The term ‘variable’ describes the fluctuation of windand solar electricity generation in response to changing
weather conditions, independently of changes in demand(see Glossary). This fluctuation makes these energy sources
less controllable than ‘dispatchable’ resources (such ashydropower, gas-fired generation or demand side response),
for which output can be increased or decreased rapidly

in response to supply scarcity or fluctuations in demand(see Glossary) (Hogan, 2012). Solar and wind electricity
generation technologies are, therefore, qualitatively
different from the perspective of the system operator, andrequire a more flexible power system to respond quickly
to fluctuations in supply (IEA, 2016). While small to
medium shares of variable renewable generation (less than
40% of annual generation, according to IEA analysis)1
have a negligible impact on traditional electricity market
operations and costs, their high penetration introduces
new challenges for balancing demand and supply in realtime (IEA, 2014). This calls for a transformation of power
markets that have, for more than a century, been designed
around centralised and predominantly thermal (fossil-fueland nuclear based) electricity generation (IEA, 2016).

Figure 2: Gross electricity generation by fuel in GWh
1,000,000

800,000

GWh

600,000

400,000

200,000

0‘90 ‘91 ‘92 ‘93 ‘94 ‘95 ‘96 ‘97 ‘98 ‘99 ‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09 ‘10 ‘11 ‘12 ‘13
Year
Coal

Oil

Gas

NuclearRenewable energies

Waste (non-renewable)

Net imports

Source: Eurostat (2015a).

1

Based on case studies of Brazil, ERCOT in Texas, Italy, Iberia, East Japan, and NWE in Australia, the IEA finds that a share of up to 40% of renewables
in annual generation can be facilitated with current levels of flexibility.

14

ODI Report1.2 Loss of flexible capacity
Alongside, and linked to, the rise in renewables, asignificant share of flexible power generation capacity ina number of EU Member States has been retired. This has
been driven by four key factors across the region:•• success in support for renewable electricity production
technologies and a fall in their costs•• a widespread drop in electricity demand2•• a significant number of coal- and gas-fired power plants
in the region reaching the end of their operational lives•• environmental policies leading to the phase out of highemitting plants.
In part, these developments have led to overcapacity and,in turn, exceptionally low wholesale electricity market
prices across the EU (which dropped by up to 50% in
France and Germany between 2008 and 2014) (OECD,
2015; European Commission 2014a; Genoese andEgenhofer, 2015).3
In addition to falling average electricity prices over thecourse a year, renewables (particularly solar) can also reducethe incidence of electricity price peaks over the course ofa given day, as they can provide low-cost supply in timesof high demand (Gray et al., 2015). High solar electricity
generation, for example, often coincides with periods ofhigh electricity demand at midday. In Germany, high windand solar electricity production on sunny or windy days haseven driven wholesale electricity prices down to negative
levels4 (European Commission, 2015b; Morris, 2015).
While the drop in wholesale prices is effective insignalling that there is a surplus of generation capacity
and that hence disinvestment is needed, in the context
of an increasing share of variable renewable electricity
generation and decarbonisation targets, the type of
capacity that retires is of relevance (Hogan, 2012; Buck etal., 2015). The retirement of capacity becomes problematicwhen the more flexible and lower carbon generation

units close, such as combined cycle gas turbines (CCGTs),rather than the higher carbon and less flexible generation
units, such as old coal-fired capacity – a scenario that is
beginning to play out in Europe.
Gas-fired power, typically the most flexible of generation
technologies, has also been the most expensive in thecontext of low coal and carbon prices. As a result, it ismost likely to be pushed out of the market when renewablegeneration is high (Caldecott and McDaniels, 2014).
Increasing shares of renewable electricity production have,therefore, caused thermal plants, (and in particular flexible
CCGTs) to run fewer hours and at lower load factors.
Between 2008 and 2013, the average utilisation rate of
all thermal plants (coal, gas and nuclear) across the EU
dropped from 50% to 37%. This has made it more difficult
for these plants to recover their fixed and operationalcosts by selling their electricity on the wholesale electricity
market (Coibion and Pickett, 2014).
Falling utilisation rates have major implications for
power companies that have large conventional, often fossil
fuel-based, generation assets. According to Carbon Tracker
Initiative (CTI), the largest five power generators in Europe(EDF, GDF Suez, Enel, E.ON, and RWE) lost more than€100 billion ($128 billion) collectively between 2008
and 2013 (representing 37% of their value) on a market
capitalisation basis (Gray et al., 2015). As a result, theEU is seeing increasing mothballing (see Glossary) as wellas increasing rates of premature closure of power plants(Caldecott and McDaniels, 2014). In 2012 and 2013, 10
EU utilities had plans to close or mothball over 20GW of
CCGT capacity, almost half of which had been built or
acquired within the past decade (Caldecott and McDaniels,
2014). European power markets are, therefore, losing
flexible and, relatively lower-emission power plants (i.e.
gas instead of coal) at a time when increased flexibility isnecessary to complement an increasing share of variable
renewable electricity generation. This is heightening
emerging concerns about security of supply.

2. Driven by economic slowdown, mild weather and improvements in energy efficiency demand for electricity in Europe dropped 3.3% between 2008 and2013 (Gray et al., 2015). Forecasts for future electricity demand in the EU vary substantially. ENTSO-E forecasts demand to increase by 0.8% annually
between 2016 and 2025, based on the highest electricity demand forecasts of the different System Operators (ENTSO-E, 2015). Carbon Tracker Initiative
forecasts electricity demand to continue to decline by 0.3% from 2014 to 2030 (Gray et al., 2015).
3This drop in wholesale electricity prices is not reflected in retail prices, which have increased on average over the same period. According to the European
Commission, this might suggest that price competition in retail markets is weak, enabling suppliers not to pass on wholesale price reductions to theirconsumers (European Commission, 2014a). Regulated retail prices in some Member States, as well as taxes and levies, also play a role.

4

Negative prices occur because, for some market operators (i.e. nuclear plants), it is more expensive to reduce output than to keep operating at full
capacity but at a loss (IEA, 2016; Morris, 2015).

Rethinking power markets: capacity mechanisms and decarbonisation 15  

2. Capacity mechanisms:
rationale, types andcurrent demands
2.1 The historic rationale for introducing
capacity mechanisms
Although new concerns about security of supply linked to
the wider transformation of energy systems have reignitedinterest in capacity mechanisms (CMs), they are not a
new instrument. They have been introduced in various
power markets in the past, particularly in the US and Latin
America, to address concerns about security of supply,
which has been a persistent challenge for system operatorsand energy policy makers.
To understand the different approaches taken to
maintain the reliability of the power system it is essential
to understand the different elements that form part of thechallenge of ensuring security of supply, and the rationale
for government interventions through a CM.
To ensure power system reliability, electricity demandand supply must be balanced in real-time, or on a secondby-second basis. When supply exceeds demand or isinsufficient to meet demand the balance in the electricity
system is disrupted, in turn causing blackouts (NIC, 2016).
The electricity system must, therefore, have sufficient
resources to respond to unexpected power plant shut
downs or fluctuations in demand. While fuel security isalso important for security of electricity supply, this relatesless directly to electricity market design, and is, therefore,
not discussed in this paper.
To assess and address power system reliability(see Glossary) many countries across the world have
performance standards, for which different metrics areused.5 Not all European countries have such reliability
standards in place,6 but most that do express their standard
in the number of hours per year or over a set period during
which involuntary power system failures or blackouts may
be expected. As outlined in section 3.1, these reliability

standards are often set to conservative levels, which may
not reflect the value of uninterrupted supply to consumers
and, therefore, increases the risk of expensive overcapacity(IEA, 2016).
The challenge to continuously balance electricity
demand and supply to uphold reliability standards consistsof two elements:•• resource adequacy (i.e. are there sufficient resources
available – including generation capacity, demand side
response and transmission capacity – to meet the needsof electricity consumers).
•• operating reliability (i.e. the ability of the system torespond to sudden shocks such as unexpected shutdownsof generating plants and restore the balance between
supply and demand) (IEA, 2016); Hogan, 2015a.
While the first question applies mainly to longer-term
investment timescales, the second applies to operationaltimescales, or the short-term functioning of the electricity
system (Hogan, 2012; IEA, 2016). Governments, system
operators and national regulatory agencies (NRAs) takedifferent approaches so that sufficient investments are
made in power market resources to ensure security ofsupply in the short and long-term.
Traditionally, the question of security of electricity
supply has been dealt with primarily on the supply side.
Enough generation capacity was built and operated tomeet forecasted peak demand; with fluctuating demandlevels being perceived as given (or largely uncontrollable).
Power system reliability was, therefore, perceived largely
as an issue of generation adequacy (Keay-Bright, 2013).
Under this model, baseload capacity delivers the supply
that is needed at all times through inflexible or less flexible

5

The IEA has surveyed 30 electricity systems in its Member Countries, of which 22 had reliability standards that were set explicitly by governments (IEA,
2016).

6

Despite EU efforts to integrate energy markets, ensuring security of supply remains in the hands of each Member State, which can take its own preferredapproach.

16 ODI Reportgeneration capacity (nuclear or coal-fired generation).
More flexible mid-merit power plants (like CCGTs) adjust
their output in response to fluctuating demand throughout
the day and fill the gap between base- and peak-load.
Flexible peaking capacity, including open cycle gas turbines(OCGTs), diesel engines, or hydro-power, delivers thehighest or peak-demand levels (Keay-Bright, 2013).
Following power market liberalisation efforts,7
governments have taken different approaches to ensuresufficient incentives for investment by market operatorsin the different resources that are necessary to meetmaximum forecasted demand. Historically, many European
power markets have opted for relatively little intervention
and have operated so-called energy-only markets, with
providers of capacity remunerated only for the electricity
produced and sold in the wholesale electricity market. In
theory, in a competitive market without subsidies, pricecaps or other regulatory interventions, wholesale electricity
prices should be able to rise to high enough levels and doso often enough to also enable plants that only operate
at times of high demand (mid-merit and peaking plants)
to recover their fixed costs through scarcity prices (seeGlossary) (Baker and Gottstein, 2013).
The historic rationale for CMs has been that existing
government interventions,8 including price caps to keep
electricity affordable, lead to prices that do not enable
providers of mid-merit or peaking capacity to recover their
fixed costs (the so-called ‘missing money’ problem – see
Glossary). This has led to the introduction of various
types of CMs that introduce payments for capacity on
top of revenue generated from selling electricity on themarket. By introducing a source of revenue that is available
irrespective of operating hours, CMs aim to incentivise
investments in new capacity when this is deemed necessary
to meet forecasted electricity needs, and to prevent theretirement of existing capacity that is required to meet agiven reliability standard (Baker and Gottstein, 2013).9
These mechanisms come in various forms, reflecting
country-specific security of supply challenges, resource
portfolios and government preferences for different levelsof – and tools for – intervention.

2.2 Types of capacity mechanisms
The European Agency for the Cooperation of Energy
Regulators (ACER) uses the following classification of CMs,
based on whether they are quantity- or price-based, targeted
or market-wide and centralised (purchases by system

operators or governments) or decentralised (procured byelectricity suppliers or consumers) (Figure 3) (ACER, 2013):•• Strategic reserve:
A strategic reserve consists of either existing generation
capacity that would otherwise be mothballed or
decommissioned, or new generation capacity that is kept
outside the wholesale electricity market to remain available
to ensure security of supply as a last resort in situations ofsystem stress. A strategic reserve is typically quantity based(the system operator or regulator determines the amountof new or existing capacity needed for the reserve) andpayments are typically determined through a tender. In
Germany, new strategic reserves have been established in
the context of an increasing share of variable renewablesin the power mix (see Box 6 in section 4 on Germany’s
electricity market reforms).
•• Capacity obligation scheme:
Under a capacity obligation scheme, suppliers andlarge consumers must contract a certain amount ofcapacity, determined by the system operator or regulator
based on forecasted demand. A linked market for trading
capacity certificates may be established. France has plans
for a capacity obligation scheme, which was supposed
to become operational by 2016, but the European
Commission launched an inquiry into the scheme as it
believes that the proposed design is inconsistent with EU
rules (see Box 2 in section 4 on the EU’s patchwork of
CMs). This is likely to delay the planned implementationof France’s capacity obligation scheme (see Box 5 insection 4) (ICIS, 2016).
•• Capacity auction:
A capacity auction is a centralised, quantity-based
scheme in which system operators or regulators determine,
typically a few years in advance, the level of capacitythat will be required to meet forecasted levels of demand.
This capacity is then procured through an auction thatsets a price that is paid to all capacity providers that bid
successfully in the auction. The UK has implemented acapacity auction scheme, with the first two auctions heldin 2014 and 2015. The results exposed some significant
flaws in the UK’s CM design, as it is failing to sufficiently
promote flexibility in the system and is incentivising highcarbon power generation (see Box 4 in section 4 on the
UK’s capacity auction).

7

Since the 1980s, market liberalisation efforts have sought to increase the role of the market in determining the level of investment in generation capacity.
However, even in liberalised electricity markets, the sector remains heavily regulated and affected by government policies that have a very significant
influence on the power mix (IEA, 2016).

8

Government interventions may aim, for example, to promote the deployment of renewable energy technologies, to increase competition or to ensure theaffordability of electricity.

9

Sweden introduced a strategic reserve in 2003 after market liberalisation in response to concerns about security of supply following the shut-down ofmany diesel engines that could not compete in the liberalised market.

Rethinking power markets: capacity mechanisms and decarbonisation 17  Figure 3: Types of capacity mechanisms

Capacity mechanisms
Quantity-based

Targeted mechanism

One-off
tenders

Strategic
reserve

Price-based

Market-wide mechanism

Capacity
obligation

Capacity
auctionDecentralised

Centralised

Capacity
payment

Source: Baker et al. (2015).

•• Capacity payments:
Capacity payments provide a fixed price to providers of
capacity for their contribution to security of supply. The priceis determined by an independent body, while the providers of
capacity determine the level of capacity they can provide on
basis of those payments. Capacity payments have been in use
in Spain since 1996 and in Greece since 2005.
•• Reliability options:
Consumers, or an independent body acting on theirbehalf, buy reliability options from capacity providers fora fixed fee. The option is exercised when the wholesale
electricity market price (spot price) is higher than a pre-set
reference price. When this happens, providers of capacity
are required to pay the difference between the wholesale
electricity price and the fixed fee to consumers. Italy has
recently implemented a capacity market with reliability
options (Eurelectric, 2015).
There can be substantial variations in the design andimplementation of the different types of CMs based on
different methodologies for forecasting future demand
and assessing security of supply; the different types ofcapacity that are allowed to participate in the scheme;
different timescales; and different cost recovery methods(although charges tend to be applied to the suppliers who,
in turn, typically pass the costs on to the end consumers).
Addressing the general benefits and disadvantages ofthese various types of CMs falls outside the scope of thispaper (for a more detailed discussion see ACER, 2013 orHancher et al., 2015).

18 ODI Report

2.3 A new security of supply challenge
Although CMs are not a new tool, the increase in variable
renewable electricity generation has fundamentallychanged the nature of the security of supply challenge thatCMs were traditionally designed to address.
As discussed in section 1.2, high shares of variable windand solar electricity generation reduce the need for, andviability of, fossil fuel- and nuclear baseload and midmerit generation (see Figure 4 on forecasts for Germany).
When wind and solar outputs are high, mid-merit andpeaking plants will either not run at all, or run at lower
load factors. Indeed, the IEA forecasts that, in a scenario
which it deems consistent with the goal of limiting global
temperature rise to 2°C, gas-fired capacity in the EU
installed by 2040 will only run, on average, at 12% of full
capacity (IEA, 2016).
Acknowledging this, Steve Holliday, the outgoing CEO
of National Grid, the company that operates gas andpower transmission networks in the UK, has said that‘the idea of large power stations for baseload is outdated’(Beckman, 2015). Instead, there is an increasing need for
power systems to respond to strong and frequent variations
in wind and solar generation, and inflexible assets thatcannot adjust their output in response to fluctuations inrenewable generation will increasingly pose a threat to thereliability of power systems (Gottstein and Skillings, 2012).
The operational qualities of power system assets,
particularly their ability to adjust generation output or
demand quickly in response to variations in renewableelectricity supply in the short-term, are therefore ofFigure 4: Estimated power demand over a week in 2012 and 2020, Germany

A week in May 2012

A week in May 2020

80

Gigawatt

60

40

20

0

Mon

Tue

Wed

Thu

Fri

Conventional
Pumped Storage

Renewables
Solar

Coal and Gas
NuclearWind
Biomass
Hydro

Sat

Sun

Mon

Tue

Wed

Thu

Fri

Sat

Sun

Source: Morris and Pehnt (2015increasing importance. In this context, it is evident thatthe traditional ‘generation adequacy’ approach to CM
design that focussed on supply and fails to value operating
capabilities (flexibility) is no longer suitable to ensure
security of supply.
At the same time, rapid technological advances
mean that governments, system operators and national

regulatory agencies (NRAs), have access to a growing
number of low-carbon options to increase flexibility in the
power system. The following section outlines options tobuild low-carbon and secure power systems.

Rethinking power markets: capacity mechanisms and decarbonisation 19  

3. Beyond capacity
mechanisms: options tointegrate increasing sharesof renewable electricity
An increasing number of options are available that,combined, can help to ensure the reliability of the powersystem in the context of an increasing share of variable
renewable electricity production in a cost-effective manner.
These can be divided into options to first, improve system andmarket operations, and second, add flexibility to the system.
Analysis by the International Energy Agency (IEA)
has found that when variable renewables make up morethan 45% of generation mix, shifting to a more flexible
resource portfolio reduces system costs by two-thirds
when compared to a situation where the resource portfolio
remains unchanged10 (IEA, 2014). Similarly, the Office of
Gas and Electricity Markets (Ofgem) the UK Government
regulator for gas and electricity markets, found that
improved system flexibility in the UK power market not
only improves reliability and reduces the need for new
high-carbon peaking plants, it could also save consumers
about $11.74 billion (£8 billion) a year by 2030 incomparison to a less flexible system (NIC, 2016).

3.1 Improving system and market
operations
Improving system and market operations can support
the more efficient utilisation of existing assets, whichcan, in turn, reduce the need for back-up generation andadditional flexibility in the system.

3.1.1 Reassessing reliability standards andassessments
With the intention to prevent blackouts as much as
possible, governments tend to adopt conservative reliability
standards that may not reflect the value of uninterrupted
supply to consumers. This can lead to over-investment

relative to electricity system needs, and stranded generation
assets (see Glossary) (IEA, 2016).
These standards need continuous reassessment to ensurethat they reflect technological innovation and market
developments and are not so demanding that they leadto investments in costly generation capacity that is rarely
used. Ideally, reliability standards should also reflect thevalue of uninterrupted supply to consumers. However, as
the value of uninterrupted supply varies across consumers,
time of day and year, it is difficult to estimate the value ofloss load (VOLL) in practice (IEA, 2016). As a result, we
see very different standards across neighbouring countries.
In the UK, for example, the reliability standard has been
set at three hours expected loss of load per year (see Box
4 in section 4), compared to eight hours in Ireland (CEER,
2014; Keay-Bright, 2013; IEA, 2016).

3.1.2 Pricing
Removing price caps can help to improve the ability ofthe market to reflect scarcity value (see Glossary) andcan, therefore, enable markets to better reward flexibility.
Allowing wholesale electricity prices to rise in times ofsupply scarcity enables peaking and mid-merit plants that
only operate in times of high demand or unexpected supply
interruptions to recover their fixed costs. This also provides
price signals that can incentivise investments in new capacity
when this is needed (ECFIN, 2015). Another way for themarket to better reflect scarcity value is by ensuring that thecosts of reserves and ancillary services (see Glossary) thatare required to balance demand and supply in real-time arereflected in the day-ahead and intra-day electricity market(Hogan, 2015a) (see Box 1 for background).
The introduction of locational pricing, as introduced
successfully in wholesale electricity markets across the US,

10 This estimate assumes a strong decrease in the number of baseload power plants and an increase in mid-merit and peaking generation plants and demandside response, as well as improvements in grid infrastructure management.

20 ODI ReportBox 1: A brief introduction to electricity markets
To prevent blackouts, a balance between electricity demand and supply needs to be achieved on a second-by-second
basis. To ensure that this balance can be reached from season to season, at different times of the day, and in theevent of unexpected supply interruptions or demand peaks, system operators purchase contracts of different lengths.
System operators purchase long-term contracts years ahead (including power purchase agreements (PPAs) andcapacity contracts) and months ahead in the forward market (Figure 5). In the shorter term, electricity is tradedin the day-ahead and intra-day markets (Keay-Bright, 2013; NIC, 2016). The bids in these markets are ranked inascending order, together with the amount of energy that will either be generated or that, if demand-side response
also participates in the market, can be reduced to create a merit-order (see Glossary). The forecasted levels of
demand determine the marginal bid and, therefore, the wholesale electricity price, as well as which resources will
be deployed to meet demand.
When the electricity system is imbalanced in real-time as a result of unexpected power plant outages or demand
peaks, system operators are responsible for deploying balancing and ancillary services to prevent blackouts (seeGlossary). This can be done by paying generators to increase or decrease their supply, paying consumers to adjust
or shift their electricity consumption or by use of other ancillary services (Keay-Bright, 2013; IEA, 2016; NIC,
2016).

Figure 5: Different building blocks of electricity markets

Long-term
15-35 years
ahead
New capacity
Capacity
EnergyMedium-term

3-4 years
ahead

Short-term

Month
ahead

Day ahead(h-24)

IntradayDay-aheadmarkets

Intradaymarket30-60
minutes

DeliveryTime

PPA and longterm contracts
CapacitymarketForwardmarkets

Ancillary services and operating
reserves procurement

Reserves

Not in all markets

Balancing/real time
markets

Systemoperations

In all markets

Key point: A suite of interrelated markets is used to match generation and load in the short, medium and long term.
Source: OECD.IEA 2016 Repowering Markets, IEA Publishing. Licence: www.iea.org/t&c

can incentivise investments where they are most needed.
This increases the business case for local-level storage anddemand-side response (see section 3.2). In the EU, prices
are mostly uniform over large areas that are, in manycases, defined by borders between countries (IEA, 2016).
Shorter scheduling intervals for balancing markets (seeGlossary) can also help pricing to better reflect scarcity
close to real-time and increase the value of flexible assets inthe electricity market.
In addition, scarcity value can be better reflected in retail(consumer) prices, by offering customers time-of-use
pricing (linking wholesale electricity prices that fluctuate

every hour to consumer prices) or smart metering
technologies that give consumers information about theirelectricity consumption and costs. This can give electricity
users an incentive to consume electricity at times when it
is abundant and reduce consumption in times of systemstress, through automatic systems or manually (see section
3.2). All EU Member States are now rolling out smartmetering (European Commission, 2016a).
These different pricing options can all help to achievea more efficient utilisation of resources and, therefore,
provide a cost-effective way to increase the reliability ofthe power system.

Rethinking power markets: capacity mechanisms and decarbonisation 21  

3.1.3 Interconnection
Interconnection enables electricity to flow across countries
and sub-national electricity markets through powerlines, enabling the exporting of electricity in times ofexcessive supply and the importing of electricity in timesof system stress. This, in turn, allows for a more efficientuse of existing assets across countries, given that peaks ofsupply and demand do not always occur in neighbouring
power markets at the same time (Pöyry, 2013). In
addition, aggregating wind and solar capacity over larger
geographical areas reduces variability in supply – i.e.
when the wind does not blow in France, the sun might
be shining in Spain. The possibility to import electricity
from Spain in such cases reduces flexibility needs.
According to a study by Booz & Company (2013) for the
EU Commission’s Directorate General (DG) for Energy,
better connected electricity markets in the EU could offer
wider benefits ranging from €12.5 billion to €40 billion($13 - $43 billion) annually by 2030. The study foundthat expanding interconnector capacity could provide
direct benefits of about €50-€150k/MW/yr ($53-$160k/
MW/yr) (Booz & Company, 2013). The EU is accordingly
aiming for a 10% interconnection level by 2020 and 15%
by 2030 (European Commission, 2015c). National Grid,the system operator of the UK, estimates that the net valueof doubling the UK’s interconnector capacity to 8-9 GW
would be £3 million ($4.4 million) a day, because increased
interconnection would reduce wholesale electricity prices(National Grid, 2014a; NIC, 2016).

3.1.4 Other options to improve market operations
In situations of over-capacity, it may be more efficient
to enable the retirement of surplus inflexible generation
assets than to postpone their exit through regulations or
government interventions (Buck et al., 2015). This can help
to increase the utilisation of existing flexible generation
assets and incentivise investment in new more flexible
assets (European Commission, 2013). Electricity saving
measures can also reduce gross electricity consumption
significantly (9% by 2050 compared to consumption levels
in 2000), and therefore, the need for additional resource
capacity (Boßmann et al., 2015). The addition of renewableelectricity generation capacity can also be optimised froma power system perspective. This could include ensuringthat capacity is developed close to demand centres orusing less variable generation technologies, such as windturbines with larger rotors that generate more electricity atlower wind speeds than wind turbines with smaller rotors(IEA, 2014). In addition, better weather forecasts can
reduce uncertainty about real-time renewable electricity
generation and, when combined with closer to real-time

market trading, this can help to achieve a better balance
between demand and supply (IEA, 2014).

3.2 Adding flexibility to the system
In addition to options to improve market operations, anincreasing number of resources are available that can add
flexibility to the power system. These can make electricity
systems better equipped to respond to fluctuating levels ofwind and solar electricity generation11 and include demandside management and storage solutions.

3.2.1 Demand side response
Demand response is the adjusting or shifting of electricity
consumption in response to supply fluctuations in realtime, either on a contractual basis or in response to
price signals. It can be undertaken by paying electricity
consumers (business and households) to temporarily
reduce or shift their consumption (i.e. turning-down
air conditioning) in times of high electricity demand or
to increase consumption during times of oversupply.
Demand side response can, therefore, play a crucial role
in responding to variable renewable electricity generation(ECFIN, 2015). The companies that intermediate thisprocess at larger scale are known as demand-side response
aggregators. Because demand-side response can reduce
electricity consumption and help to better match demandand supply, it saves emissions and reduces system stressevents that can lead to higher electricity prices.
In the US, demand-side response is already providing
substantial benefits in terms of security of supply andcost savings for consumers.12 One company in the US has
found, for example, that sending text messages and emails
to its customers during times of peak demand has helped
to reduce these peaks by 3-5% (O Power, 2016). Acrossthe EU, however, the potential of demand side response
is still far from being tapped. While some Member
States have adjusted regulations to facilitate the uptakeof demand response (e.g. France and Ireland), in othercountries (e.g. Spain, Italy, Germany, Poland, Netherlands)
the development of demand side response is still hinderedby regulatory barriers (for example, providers of demandside response may not be allowed to participate in thewholesale electricity market) (SEDC, 2015). According
to Miguel Arias Cañete, EU Commissioner for Climate
Action and Energy, deploying demand side response acrossthe EU could generate savings of up to €100 billion ($107billion)a year, or almost €200 ($213) per European citizen(European Commission, 2015d). Recent analysis finds that
if 5% of peak demand in the UK were met by demand side

11 As selling electricity has traditionally been the main source of revenue in electricity markets, and some of these options help to reduce electricity demand,
there is a need to consider how these services can be rewarded within these markets.
12 Direct benefits to consumers were estimated at $2.2 billion in 2014 (SEDC, 2015).
22

ODI Reportresponse, electricity system costs could be reduced by £200
million ($294 million) a year (NIC, 2016).13

3.2.2 Storage technologies
Storage technologies enable consumers and electricity
suppliers to store electricity for use when it is mostneeded. This avoids the need to require (or pay) renewableelectricity providers to stop generation at times of supply
surplus, which can come at a high cost. In the UK, forexample, wind farms are paid £90 million ($132 million) a
year to curtail electricity production during times of oversupply (NIC, 2016).
Storage solutions differ greatly in terms of costs andbenefits, and technologies range from compressed air,
pumped hydro, flywheel and battery storage (including
in electric vehicles). They also differ in their application:
while some technologies will store energy for minutes
or hours, others store electricity across seasons (Lazard,2015). In addition, while some storage technologies (suchas pumped hydro and compressed air) already have astrong business case, other technologies are at earlier stagesof commercialisation.
Over the past decade, however, a great deal ofinnovation has been achieved around battery technologies(such as Tesla’s lithium ion ‘Powerwall’), which arebecoming increasingly commercially competitive, withcosts falling from $3,000/kWh in 1990 to below $200/
kWh in 2015 (NIC, 2016; FS-UNEP, 2016). Lazard (anasset management company) forecasts that within five
years a number of battery technologies, such as lithium-ion
and flow batteries, will be competitive against back-up
gas-fired power generation as an option for complementing
variable wind and solar renewable electricity generation(Lazard, 2015). Some case studies suggest that solar

electricity generation combined with utility-scale battery
storage is already competitive with fossil fuel based
electricity generation (FS-UNEP, 2016).
As with many technologies, cost-competitiveness,
however, may not be sufficient to unlock the potentialof storage options. In the UK, for example, the National
Infrastructure Committee (NIC) has called for regulatory
reforms to enable the participation of storage providers
in electricity markets, and to prevent storage from being
subject to double-charging for the use of the electricity
network both when electricity is stored and when it isreleased for use (NIC, 2016).
The rising number of low-carbon options for enhancing
the balancing of demand and supply, mean that it ispossible for governments redesign power market design andregulatory frameworks to promote flexibility and facilitate
the uptake of an increasing share of renewable electricity
generation. This will, in turn, support the move away from
centralised, mostly fossil-fuel fired generation to more
decentralised electricity generation, an increasing number ofmarket players, and a more proactive role for consumers.
Recognising that past approaches to capacity
mechanisms have become outdated in the context of achanging reliability challenge, and that new opportunities
exist to ensure the reliability of the power system, CMs
in the US and the EU have been adapted, with varying
degrees of success (See Boxes 2-6 in section 4). Building
on a review of experiences with CMs and wider electricity
market reforms in France, Germany, the UK and theUS, the following section suggests that approaches toensuring the reliability of the power system require awider reconsideration of opportunities for a low-carbon
transformation of the power system.

Rethinking power markets: capacity mechanisms and decarbonisation 23  

4. Designing andimplementing capacity
mechanisms – risks
to wider energy policy
objectives
Whether the introduction of any type of CM is suited
to address emerging concerns about security of supply
depends on the power-mix,13 market or mechanism design
and the implementation process. These are all, in turn,functions of political context, wider electricity market
design and integration with neighbouring and coupled14
power markets (Caldecott and McDaniels, 2014).
Even without today’s pressing decarbonisation needs
and a rapidly transforming electricity market, the careful
design and implementation of CMs has been a greatchallenge. Like all administrative solutions, CMs havepractical constraints and their design and implementation
introduce human and political factors that can result inunintended outcomes (Hogan, 2015b). They also create
a new layer of regulatory complexity, while electricity
markets undergo continuous transformation.
Our analysis of planned and existing CMs in France,
Germany, the UK and the US highlights the existingand new challenges associated with their design andimplementation. These can be categorised as political risks(section 4.1), technical risks (section 4.2) and institutionalrisks (section 4.3). This analysis also highlights how CMs
can undermine parallel objectives of decarbonisation andthe phasing out of fossil fuel subsidies, as well as economic
efficiency and electricity market integration (Box 2).

4.1 Political risks
An analysis of experiences with CMs in France, Germany
and the UK suggests that designing and implementing
capacity mechanisms involves political risks. These include
risks of regulatory capture by vested interests and ofconcentrating benefits to incumbents.

4.1.1 Regulatory capture (by vested interests)
The consultation process for the design of CMs carries a riskof regulatory capture by incumbent market players that havebetter access to resources and information and are, therefore,
better equipped to lobby. Incumbent market players – often
power companies with fossil fuel or nuclear generation
assets – can only be expected to aim to protect their own
interests: the profitability of their existing assets and theirinvestments. This creates the risk that CMs are implemented
where they are not needed or designed in a way that
‘suppresses innovation and new entry while privatizing
profits for incumbents and socialising risks’ (Hogan, 2015b).

13. In Germany, for example, concerns about security of supply stem from the limited possibilities to transport electricity from areas in the North with anoversupply of wind-generated electricity to areas of high demand in the South (see Box 6). In France, the reliability challenge relates to a high usage ofelectric heating, which has created an intense peak-demand phenomenon (RTE, 2014). Since 1990, the peaks in consumption have increased faster thanoverall electricity consumption (Hubert, 2015), increasing the difference between average and peak demand for electricity (see Box 5).
14 Market coupling is the integration of two or more neighbouring electricity markets through an implicit cross-border allocation mechanism. Market
coupling ‘brings all bids and offers from different national power exchanges for cross-border trading into one ‘basket’ and allows matching them in an
optimal manner across borders.’ In Europe, market coupling has been used to integrate electricity markets across different areas (Glachant, 2010). The
efficiency of markets over large geographic areas requires strong coordination and the consolidation of balancing areas. (IEA, 2016).

24 ODI ReportBox 2: A patchwork of capacity mechanisms – undermining EU regional efforts on security of supply?
Recognising the significant benefits of integrating power markets across a larger geographical scale to enable more
efficient utilisation of existing resources and improve the reliability of the power system, Europe has gradually
moved towards increased power market integration since the introduction of the First Energy Package in 1996.
While historically, European electricity networks were developed primarily to support national markets, electricity
market design is accordingly increasingly becoming a cross-border issue.
Regulations, however, are still catching up with this new reality. Security of supply is still regulated at theMember State level, although some EU countries15 are working together to develop a common, regional approachto setting reliability standards and to assessing reliability).
A proliferation of uncoordinated national capacity mechanisms (CMs) risks undermining internal market integration
efforts, which, paradoxically, are supposed to enhance the reliability of the power system. The EU has, therefore, notbeen supportive of the introduction of uncoordinated CMs at national level. In addition, the EU Commission has
recognised that CMs can create new State aid (EU terminology for subsidies) and conflict with decarbonisation efforts.
A 2013 communication of the EU Commission recognises that Member State-level public intervention may
be required to ensure security of supply in some Member States in the near-term, but it clearly regards CMs as alast resort. It clarifies that Member States should only consider CMs when the potential offered by other options
and wider market and regulatory reforms has been exhausted, including the removal of price caps, improving theeffectiveness of intraday balancing markets (see Glossary), cross-border trade and demand side response.
The Commission is prepared to use its legal powers under the EU State aid16 rules to scrutinise CMs where they
have the potential to undermine the electricity market integration efforts. To this end, the Commission publisheda set of guidelines and assessment criteria for CM design in 2014 and, in 2015, as several Member States havestarted to implement planned CMs, it launched a sector-wide inquiry into these developments.
The 2014 guidelines clarify the application of State aid rules when CMs are introduced. Member States should:•• demonstrate why intervention in the market is required to ensure security of supply•• design CMs so they only remunerate availability of capacity and not electricity sold•• ensure that the measure is open to all possible providers of capacity and provide adequate incentives to all typesof capacity, including generation, demand side response, cross-border trade and storage.
To ensure that aid is proportional and does not distort competition and trade, a competitive bidding process isrecommended. Member States should also give preference to low-carbon generators ‘in case of equivalent technicaland economic parameters.’
Although this guidance leaves a lot of room for interpretation, and more detailed guidance can be expectedfrom the Commission’s investigation, a few observations can be made. First, the use of the term ‘generation
adequacy’ rather than ‘resource adequacy’ is outdated in the context of the increasing importance of resource
capabilities (flexibility and carbon intensity) and demand side response. Second, the requirement for the measure
to be open to all providers of capacity to minimise market distortions might conflict with the EU’s decarbonisation
objectives when payments prolong the lifetime of fossil fuel-fired generation assets. Third, if the requirement toprovide adequate incentives to existing and future generators keeps less flexible assets in the power mix, this will
undermine rather than support security of supply and innovation.
The EU’s efforts to establish an EU-wide approach to ensure the reliability of the power system and electricity market
integration should be strengthened to make more efficient use of capacity across Europe and improve security of supply.
Sources: European Commission (2015e; 2014b; 2013); IEA (2016).

Indeed, many conventional power companies, including
RWE and E.ON in Germany, the big six (British Gas, EDF,
Npower, E.ON UK, Scottish Power and SEE) in the UK and
EDF in France, and particularly those facing risks of stranded

coal generation assets, have put pressure on Member Statesto introduce CMs instead of alternative measures to support
the reliability of the power system (Caldecott and McDaniels,
2014). This is unsurprising as these companies’ revenues

15 These Member States include Austria, Belgium, France, Germany, Denmark, the Czech Republic, Luxembourg, the Netherlands, Poland and Sweden.
16 State aid is defined as: 1) an intervention by the State or through State resources that can take a variety of forms (e.g. grants, tax reliefs, guarantees,
government holdings of all or part of a company, or providing goods and services on preferential terms); 2) that gives the recipient an advantage on aselective basis; 3) may distort competition; 4) and is likely to affect trade between Member States (European Commission, 2013b).

Rethinking power markets: capacity mechanisms and decarbonisation 25  from selling electricity are declining and CMs create an
opportunity for a stable revenue stream, a reduction of losses
or improved market performance.
This is demonstrated by the introduction of the lignite
power stand-by security reserve in Germany, linked to thecountry dropping initial plans to introduce a climate levythat would penalise high-polluters. RWE had long lobbied
against the climate levy and, following the announcementof the new plans to put lignite in a reserve, its sharevalue rose by 6.4%. Under the new plans, the powercompanies will receive payments for shutting down theirpower plants, instead of needing to pay for the pollution
caused by lignite power stations. E3G has estimated thatthe compensatory payments to RWE may amount to asignificant 13% of its 2014 operating result from its entire
conventional business (Schwartzkopff et al., 2015).
While the mechanism is framed as a tool to cut
emissions in the power sector, it operates like a capacity
reserve. Furthermore, while only those power stations notalready listed in the closure notification list are eligible forthe security stand-by (to ensure that the standby reserve
cuts additional emissions), there are doubts as to whether
the plants included in the reserves would not have shut
down anyway, especially in the context of decreasing prices
for gas. In addition, the Government’s deliberate selectionof power plants for the reserve may be at odds with EUcompetition rules that require these market interventions
to be ‘technology neutral’. All of this suggests that the
security standby denotes a political compromise aroundthe closure of old lignite-fired power stations, rather than ameasure to support security of supply or reduce emissions.
In France, RTE, the TSO, has designed and would
operate the country’s proposed CM (see Box 5). As RTE
is owned by EDF (the dominant publicly owned electricity
provider) there is a possible conflict of interest in thedesign of the capacity obligation scheme. While the scheme
is, allegedly, designed to incentivise demand response, theEuropean Commission has raised concerns that it has astrong tendency to strengthen the dominant position of
EDF instead (European Commission, 2016b).
Recognising the interest of utilities to protect the
profitability of their assets, the EU Commission has
clarified that CMs should not result in ‘state support tocompensate operators for lost income or bad investment
decisions’ (European Commission, 2013).

4.1.2 Risk of concentrating benefits to incumbents
There is also a risk that the benefits of CMs accrue to theparticipants that dominate the market. EDF, for example,
manages about 90% of installed capacity in France anddominates the retail electricity market. EDF will, therefore,
be the biggest obligated party as well as the holder of themost capacity certificates in France’s proposed capacity
obligation scheme (see Box 5).
Regardless of the prioritisation of demand side
response over generation in the design of the French

26 ODI Report

scheme, EDF is likely to be the price setter in the capacity
market (Zgajewski, 2015). Although the mechanism
was scheduled to first deliver capacity in 2017/18, theCommission has launched an in-depth investigation into
the plans because it believes they are incompatible with
EU rules, given the risks of market concentration anddistortion (European Commission, 2016b).
When a large share of compensatory payments issecured by the incumbents, or when incumbents are themain players in a capacity market, CMs, as recognisedby the Commission ‘may have distortive effects bystrengthening or maintaining substantial market power ofthe beneficiary’ discouraging the entry of new competitors(European Commission, 2014b).

4.2 Technical risks
A review of experiences with CMs in the US, the more
recent capacity market in the UK, and of the plans for acapacity obligation scheme in France and a capacity reservein Germany suggest that the design and implementation of
CMs also involve significant technical risks, including:•• overestimating future electricity needs, creating risks of
stranded assets;•• locking in inflexible capacity, which in the context
of an increasing share of wind and solar generation
undermines the reliability of the power system;•• locking in high carbon generation, which undermines
decarbonisation objectives;•• creating new fossil fuel subsidies that undermine fossil
fuel subsidy phase-out objectives; and•• creating barriers to innovation.

4.2.1 Risk of overestimating future electricity demand
Quantity-based CMs carry the risk of overestimating future
electricity needs, leading to the lock-in of unneeded capacity
and, in turn, stranded assets (see Glossary). Forecasting thefuture needs of power systems is a particular challenge in thecurrent context of rapid technological innovation and market
transformation. One study that compared capacity mechanisms
in the US with the energy-only National Electricity Market(NEM) in eastern Australia found that CMs were more likely
to lead to over-procurement of capacity than markets that relyon scarcity prices and the pricing of ancillary services to attract
investments (Hogan, 2015a).
In its assessment of the UK’s plans for a capacity market,
the European Commission warned that the planned scheme
would overestimate capacity needs as a result of overly
conservative assumptions, in particular for interconnector
capacity (European Commission, 2014c) (see Box 4).
Despite these warnings, the Commission approved the UK’s
capacity market, conditional on some improvement in its
design. Nonetheless, the first UK auction was also based onconservative expectations of the contribution of demand

side response, assuming that its deployment would notincrease at all over the next four years (Baker et al., 2015).
A 2014 study of EU Member States’ generation adequacy
assessments found that the UK is not alone, and that many
countries fail to consider flexibility and the contribution ofinterconnection in these assessments (CEER, 2014).
To avoid the design of CMs based on overestimationsof future electricity demand, the EU Commission
requires Member States to demonstrate the need forintervention in the market. In assessing security of supply
issues (commonly the responsibility of either the TSO,
the NRA or the government), Member States shouldtake into account ‘on-going market and technology’
developments, but how they should do so is not specified(European Commission, 2014b). The EU Energy Union
Package further points out that frameworks for securityof electricity supply in many EU Member States areout-dated and inconsistent. In line with its market
integration objectives (see Box 2), the EU plans to workwith Member States to establish acceptable risk levels for
supply interruptions and an EU-wide security of supply
assessment, taking into account cross-border flows ofelectricity, variable renewable energy generation, demand
response and storage possibilities (European Commission,
2015f). A number of Member States,17 17 together with
Switzerland and Norway, are working together to develop
a common, regional approach to setting reliability
standards and to assessing reliability (IEA, 2016).
Despite these efforts, the IEA (2016) points out that a
relative lack of attention to reliability regulations in the creationof the EU’s Internal Energy Market may explain why countries
still tend to take a national-level approach to the assessment of
reliability, which can increase the cost of ensuring reliability andundermine market integration. Overestimating future systemneeds is a common risk when governments use incentives topromote investment in new capacity or infrastructure and evenso when investment decisions are left to the market. Market
participants may also fail to accurately forecast future demandor technological innovations (IEA, 2016).

4.2.2 Risk of locking in inflexible capacity
Historically, and as discussed more extensively in section
2.1, ensuring security of supply was approached largely
as a matter of generation adequacy. Therefore, traditional
CMs simply remunerated capacity, irrespective of
operational qualities (like flexibility). Today, the increasingneed for flexibility in the power system, given the growing
share of variable renewable electricity generation, presents
a paradox: fixed, undifferentiated payments for capacity
may undermine, rather than boost, the reliability of thepower system (Keay-Bright, 2013). This is particularly
the case when capacity payments keep old, less flexible
capacity in the market, which cannot adjust output in

response to fluctuating levels of renewable electricity
generation. In addition, this can discourage investment in
the more flexible resources required to facilitate the uptakeof variable renewable electricity generation.
The limitations of CMs that remunerate generation
capacity irrespective of operational characteristics became
apparent in a number of US power markets, including PJM
and ISO New England. In response to emerging issues likethese the designs of a number of CMs in the US have been
adapted continuously for more than a decade (see Box 3).
In Germany, the planned power market reforms include
an additional back-up capacity reserve with largely
inflexible, high-emitting plants. This security stand-by
removes 2.7GW of lignite-fired power plants from themarket, which, even though those power plants cannot
respond quickly to system stress events, should provide alast back-up option to ensure supply security until they aredecommissioned in 2021. This comes at an estimated costof €1.6 billion ($1.7 billion) to the German Government(Michel, 2015), which has agreed to reimburse thecompanies for lost revenues from the electricity market
during these years of security stand-by.
The European Commission has emphasised that insituations of overcapacity – an issue in a number ofEuropean power markets – security of supply concerns will
not be addressed by keeping generation capacity on thesystem. Instead, ‘Member States may consider … allowing
for the retirement of environmentally inefficient plants, forexample through the implementation of environmental
legislation or by removing subsidies’ and that ‘creating
market wide capacity remuneration schemes may under suchcircumstances be counter-productive as it may (dependingon the design) postpone the exit of inefficient capacity fromthe market’. This is, for example, the effect of continued
support for coal in Spain on revenues for newer and more
flexible gas power stations (European Commission, 2013).

4.2.3 Risk of locking in high carbon generation
By providing a new source of revenue for providersof capacity, including fossil fuel generators, CMs can
extend the lifetime of generation assets and undermine
decarbonisation efforts.
The UK provides an example (see Box 4). In its firstcapacity auction, more than 70% of the capacity payments
were secured by high-carbon assets, including coal and gas
plants and diesel generators (National grid, 2014b). Existingcoal-fired power secured 9.5% of capacity units, representing$430 million (£293 million) in payments for 2019-2020(Jones, 2014). Providers of coal-fired power were able tosecure one-year contracts and, in the case of refurbishment
plans, three-year contracts. By offering these longer contracts
for refurbishment, the capacity auction encourages coal
generators to extend the lifetime of their high-carbon

17 These Member States include Austria, Belgium, France, Germany, Denmark, the Czech Republic, Luxembourg, the Netherlands, Poland and Sweden.

Rethinking power markets: capacity mechanisms and decarbonisation 27  Box 3: United States: adapting to new market realities
Parts of the US have a long history of using capacity mechanisms (CMs), which have been introduced since
power market liberalisations, starting in the mid-1990s. Some lessons can be learned from the way in whichthese mechanisms have been adapted, often in combination with wider electricity market reforms, in response toelectricity market developments.
The limitations of CMs that remunerate generation capacity irrespective of flexibility became apparent in a numberof US power markets, including PJM18 and ISO-New England.19 Despite their success in incentivising investments in
new capacity,20 and these markets having ample capacity relative to the reference reserve margins, they experienced
increasing stress events (Genoese and Egenhofer, 2015). The CMs had the effect of extending the lifetimes of existing
inflexible capacity, and this, in turn, lowered electricity prices. This entrenched the existing mix of capacity, at a time
when this mix was becoming less fit to ensure reliability in the context of a growing need for flexibility.
In response, PJM first proposed to differentiate payments for capacity based on capabilities, so that flexibility
could be prioritised. This was, however, opposed by stakeholders and PJM decided to take a similar approach tothat of ISO-New England, which introduced a bonus-penalty scheme linked to performance during system stressevents. Rather than rewarding flexibility directly, this approach awards all capacity when it is available during
stress events. By doing so, it does promote flexibility indirectly as the more flexible assets are more likely to be
deployed to meet capacity needs during stress events.
In addition, PJM has promoted the participation of demand side response in its capacity market in three
ways. First, by enabling its participation in the wholesale electricity market and the capacity market. Second, byintroducing different categories for demand response resources to the capacity market on the basis of when they
can be deployed. Third, by adopting a differentiated auction process. Demand side response has helped to reducethe costs of meeting the reliability standard by an estimated 10-20% in 2014/15, delivering estimated consumer
cost savings of $1.2 billion (Keay-Bright, 2013). More recent reforms also allow demand side response resources tosubmit aggregated capacity market offers together with other resource types (such as storage and energy efficiency).
In addition to these reforms to the capacity mechanism, PJM and NY-ISO 21 also ensured that market prices canbetter reflect the cost of balancing supply and demand in real-time (after gate closure). They did so by ensuringthat day-ahead and intra-day electricity market prices also reflect the value of the reserves or other balancing
services needed to ensure power system reliability.
Finally, US wholesale electricity markets (including those with CMs in place) have moved to more locationbased pricing (nodal pricing). This has helped to create stronger price signals that reflect local imbalances in supply
and demand and, therefore, incentivise investments where these are most needed (geographically), including intransmission and distribution.
Sources: Hogan (2015a); Gottstein and Skillings (2012); Hurley et al. (2013).

and less flexible fleet. This is at odds with a recent UK
Government decision to phase out coal-fired power by 2025.
Diesel generators, the dirtiest form of electricity
generation, secured capacity contracts worth (£109 million
in the first capacity auction, and won 15-year contracts
worth $258 million (£176 million) in the second auction(Aldridge, 2015; Jones, 2015b). These highly polluting
generation units, which have a higher carbon intensity
than coal and emit other air pollutants that pose a threat

to human health, are exempted from environmental
regulations because of their small size (Jones, 2014). Whatis more, they already receive large payments for theircontribution to balancing services (including through the
Short Term Operating Reserve) (Orme, 2016).
Recognising the risks posed by CMs to decarbonisation
objectives, the European Commission has warned that theyshould not increase carbon intensity and must avoid locking-in
high carbon generation (European Commission, 2013).22

18 PJM is the regional transmission operator in the US that coordinates the movement of wholesale electricity in 13 states and the District of Columbia ineastern US.
19 ISO-New England is the Independent regional transmission organisation operator overseeing the operation of New England’s power system.
20 Existing resources still receive the largest share of capacity market revenues in PJM. In the 2017/2018 delivery year, existing resources will receive $6
billion in revenues, compared to $1 billion for new resources (IEA, 2016).
21 The Independent System Operator that manages the markets in New York State.
22 It must be noted that CMs are no decarbonisation tools. Wider decarbonisation of the energy sector requires carbon pricing and other policy tools thatshould not be undermined by CMs (where they are deemed necessary) – see section 5.

28

ODI ReportBox 4: The UK capacity auctions – subsidising new dirty power generation and undermining flexibility
The retirement of two-thirds of existing power stations by 2030, combined with a rise in variable renewablecapacity, underpins concerns about security of supply in the UK (NIC, 2016).23 In 2013, to address these concerns,
Ofgem (the regulator for gas and electricity markets), the Department for Energy and Climate Change (DECC),
and National Grid (the UK’s TSO) introduced two new strategic reserves on top of the existing Short Term
Operating Reserve (STOR). These new strategic reserves include a demand-side balancing reserve (DSBR) and a
supplemental balancing reserve (SBR), that are kept outside the wholesale electricity market, and are activated toaddress short-term security of supply issues.24 In addition, the UK Government has introduced a capacity auction
scheme – operational since 2014 – to address more long-term security of supply issues.
The UK’s annual capacity auctions procure capacity either in the form of existing or new generation, demandside response (DSR), storage or interconnection, to ensure that future demand (forecasted four years ahead) canbe met. 25 National Grid is responsible for forecasting the capacity required to satisfy the reliability standard,
which requires that Loss of Load Expectation (LOLE) not to exceed three hours per year. All but 2.5GW ofrequired capacity is procured four years before the delivery year in a capacity auction (T-4 auction) and theremaining 2.5GW is reserved provisionally for a one-year ahead capacity auction (T-1). Existing and new capacity,
including providers of nuclear power and DSR, are eligible to participate, while renewables that benefit fromexisting support schemes are not. DSR providers can participate in the T-4 auction or the T-1 auction, but are notpermitted to participate in both. They are encouraged to participate in the T-1 auction, but when they do so theymight be prevented from contributing to security of supply if too much capacity has already been procured in the
T-4 auction. Those that bid successfully receive annual payments for the capacity auctioned and they are penalised
if they fail to deliver contracted capacity during a stress event. Capacity payments are funded by consumers
through charges by electricity suppliers, and are estimated to cost $20 (£14) per UK household per year.
A number of concerns can be raised regarding the design and implementation of the UK’s capacity auction.
Firstly, it can be questioned whether the capacity market is needed in the first place. Ofgem has stated that themarket is likely to be able to respond effectively to scarcity from 2017/18 as the result of falling demand, and thereturn to the market of a number of previously ‘mothballed’ 26 plants.
As currently designed, the UK capacity auction could also result in overcapacity and stranded assets. Demand
forecasts, which determined the capacity needs for 2018/19, were based on conservative expectations of thepotential contributions of interconnection and demand side response,27 as well as of the availability of both coaland gas fired generation.28
Furthermore, although the UK’s capacity auction is designed to be technology neutral, the Government hopesthat it will incentivise investments in new gas. However, only one new gas-fired plant – Trafford Power – succeededin the first auction and, so far, this plant has failed to attract the finance needed to start construction. In the second
auction, only one new gas Combined Cycle Gas Turbine plant (Carrington) managed to win a one-year contract.
To date, the largest share of capacity payments (more than 70%) has been secured by existing generation capacity,
a portion of which is already profitable without these payments.
As well as subsidising existing profitable generation and undermining decarbonisation objectives, the scheme’s
provision of undifferentiated payments that disregard operational capabilities fails to promote flexibility.29 For
example, the UK’s capacity auction has resulted in payments worth $277 million (£189 million) to nuclear power
plants, although these are inflexible assets that would have operated anyway. One UK-based energy consultancy
predicts that the auctions will even undermine near-term security of supply as those market participants that do
not succeed in the auction are more likely to exit the market as a result of decreased competitiveness.
Furthermore, low-carbon flexibility options cannot compete on an equal footing in the capacity auction. While
new generation capacity is able to access 15-year contracts, DSR and interconnection can only access one-year
contracts. This is because of a spending threshold that only allows market operators to access longer contracts
when they are making investments in new capacity or in refurbishing capacity above a set amount. As demand
reduction measures are often a cheaper option (allowing savings of $44/MWh (£30/MWh) in contrast to the costsof new generation capacity from $111/MWh (£76/MWh)), this may make the capacity auction more expensive(Green Alliance, 2015). This and other aspects of the UK’s capacity auction are now the subject of a legal challenge
by Tempus Energy, a demand side response firm, in the European General Court (Case T-739/14, OJ C18/21).
Finally, it appears that some capacity that has succeeded in the auctions will not be delivered. For example,
operator SSE announced that the coal generation units at Fiddler’s Ferry will be shut down on 1 April 2016,
despite having secured capacity payments for delivering capacity in 2018/19. Although SSE will have to pay
penalties for not delivering on its capacity contract, these penalties are likely to be lower than the costs ofcontinuing to run at a loss (Orme, 2016).
Sources: Ofgem (2015); Littlecott (2014); Harvey (2016); Cornwall Energy (2015a; 2015b); DECC (2015a; 2015b); Baker et al.
(2015); Jones (2015a; 2015b; 2014), Stacey (2015a; 2015b); Aldridge (2015); Green Alliance (2015); Energy UK (2015).

Rethinking power markets: capacity mechanisms and decarbonisation 29  The State aid guidelines require Member States to ensurethat CMs give preference to low-carbon generators ‘in caseof equivalent technical and economic parameters’ (European
Commission, 2014b). At the same time, however, the guidelines
require Member States to design their CMs to be open forparticipation by all possible providers of capacity to ensurethat they do not distort competition and trade. Without further
clarification on how governments can prioritise low-carbon
generators, it is unclear how Member States can meet thesepotentially conflicting requirements (European Commission,
2014b).

4.2.4 Risk of creating new fossil fuel subsidies
When capacity mechanisms create new payments forfossil fuel based generation, they not only undermine
decarbonisation objectives, but are also at odds with theEU’s longstanding commitment to phase out environmentally
harmful subsidies, including fossil fuel subsidies. Most
recently, in the Roadmap to a Resource Efficient Europe, theEuropean Commission called for a complete phase out by
2020. At the international level, as part of the G20, the EU
has reiterated its commitment to ‘phase out inefficient fossil
fuel subsidies’ every year since 2009.
There is a risk that CMs result in new subsidies forfossil fuel generation that will be hard to remove once they
have been introduced.18 In the US PJM capacity market, forexample, 67% of capacity payments provided in auctions
between 2014 and 2018 went to existing and new oil, gas
and coal-fired generation, with only 33% going to demandside response, energy efficiency, imports, solar, wind andsolid waste (across a total of $46 billion) (Monitoring
Analytics, 2015). The limited capacity payments for windand solar are, in part, explained by their variability, whichmeans they can only participate for 13% and 38% of theirinstalled capacity, respectively (PJM, 2014; IEA, 2016).
The UK capacity market has also led to subsidies forcoal and diesel of $548 million (£373 million) and $418
million (£285 million) respectively. Capacity contractsof 15 years mean that the subsidies to diesel will be inplace for the longer-term, while consumers simultaneously
pay a carbon price for diesel and coal fired generation(Aldridge, 2015).30 Perversely, solar-power companies(whose direct subsidies have been cut) are now installingdiesel generators on their sites to increase returns throughcapacity payments for diesel (Stacey, 2015a).
Recognising the risk that CMs can introduce new fossil
fuel subsidies, the EU State aid guidelines require Member
States to: ‘consider alternative ways of achieving generation
adequacy which do not have a negative impact on theobjective of phasing out environmentally or economically
harmful subsidies, such as facilitating demand side
management and increasing interconnection capacity;(European Commission, 2014b). If Member States dochoose to introduce CMs, they ‘should take into accountthe objective of phasing out fossil fuel generation subsidies
by 2020’ (European Commission, 2013). The payments
provided under the UK capacity auction to coal anddiesel-fired generation appear to be directly at odds withthis wider EU guidance and the commitments to phaseout subsidies. The UK Government, however, maintains
that the payments provided under the mechanism are
not subsidies because they ‘provide missing money in theenergy market’ (UK Parliament, 2016).

23 Two-thirds of existing power stations are expected to close down by 2030 because of coal, nuclear and gas plant retirement cycles (NIC, 2016), emission
control regulations and financial constraints faced by utilities (Caldecott and McDaniels, 2014). Between 2010 and 2014, the UK’s generation capacity
reduced by 5.5MW, while wind capacity, when de-rated for intermittency, more than doubled, and electricity demand declined by 6.5% (DECC, 2015a).
24 The demand-side balancing reserve (DSBR) was first enacted in November 2015 to prevent a blackout in a period of system stress, while the final safety
net – the supplemental balancing reserve (SBR) consisting of mothballed power stations – would have taken several hours to activate (Davies, 2015).
25 Interconnection has been included since the second auction.
26 Mothballing is when a power plant is not used to generate power, but is preserved (kept in working order) so that production can be resumed when needed.
27 In the first auction, interconnection was even excluded from the assessment of the capacity required to meet the reliability standard, despite analysis by
Ofgem that found that interconnections can contribute about 60% of installed capacity to meeting winter peak demand.
28 Forecasted availability was estimated on the basis of average availability, rather than actual availability at times of peak demand.
29 Increased flexibility would not only reduce the need for new high-carbon peaking plants, but would also bring down the cost of decarbonisation,according to NIC (2016), by about £8 billion a year by 2030 relative to a less flexible system.
30 The carbon price floor was introduced to create a minimum carbon price. If the carbon price in the EU Emission Trading Scheme (ETS) drops below acertain level, the carbon price floor requires companies to pay the difference to the UK treasury. The floor was designed to increase every year, but in 2014
a decision was taken to freeze it at 2015/16 levels (HM Revenue & Customs, 2014)30

ODI ReportBox 5: France: incentivising demand side response?
Significant hydro and nuclear generation capacity has enabled France to ensure energy independence and to
decarbonise its energy sector. This has also led to the promotion and uptake of electric heating in households,
resulting in an intense peak demand phenomenon. Since 1990, the peaks in consumption have increased fasterthan overall increases in electricity consumption. Meanwhile, following market liberalisation, demand side
response capacity declined from 6GW in the 1990s to 3GW in 2015. High levels of peak demand have also
coincided with an increase in the share of variable renewable electricity generation31 and the closure of coal andoil-fired plants to comply with EU environmental regulations. As a result, the French Government has become
increasingly concerned with security of supply, particularly in times of peak demand for electric heating.
To address these concerns, a law was adopted in 2010 that called for the creation of a capacity obligation
scheme. If introduced as planned, this scheme would require all suppliers to buy a set amount of capacity
certificates, determined by the French TSO on the basis of consumption levels during peak times. The certificateswould be issued by the TSOs or DSOs to operators of demand response or generation capacity based on theirprojected contributions during peak periods. Once the certificates are issued, suppliers and operators would beallowed to trade them.
This market-based approach is supposed to ensure that the prices of certificates will reflect the costs of ensuring
security of supply. By giving a bonus payment to those who exceed their obligations in times of system stress,
financed by penalties paid by suppliers that fail to meet their capacity obligation, the scheme rewards operators fortheir contribution to the grid in times of short supply.
The French capacity obligation scheme is also meant to promote the use of demand response as part of a wider
four-year government programme to open all markets to demand side response providers. To that end, it will grantpriority to demand side response over generation capacity by allowing the former to request certificates over alonger timeframe (up to a year prior to delivery, compared to three years for existing generation capacity). The
system is also designed to promote flexibility by remunerating generation or demand side response capacity on
the basis of their contribution to the grid when the system is tight. Although the market is designed to reward all
capacity available at peak-times, including less flexible assets, and thus does not directly reward flexibility as such,it is likely that more flexible assets will be of greater value to obligated parties under the scheme, as these provide
greater security for meeting capacity certificate obligations in periods of system stress.
In spite of the promise that the French scheme would promote demand response and flexibility, high levelsof market concentration (by EDF) raise concerns as to whether the mechanism, if implemented, would realise
the potential of demand side response. The complexity of the system might also create a barrier to new market
entrants. More fundamentally, it remains to be seen whether the mechanism will be introduced as planned, as theEuropean Commission has launched an in-depth investigation into its planned design. The Commission has raised
doubts as to whether the mechanism is currently necessary, and asserts that it would be likely to strengthen thedominant position of EDF. The Commission holds that, in its current form, the mechanism is not compatible with
the Guidelines on State aid for environmental protection and energy.
Sources: RTE (2016; 2015; 2014); Hubert (2015); Veyrenc (2015); European Commission (2016b; 2015g); Nome Law (2010)

4.2.5 Creating barriers to innovation
If a CM is not flexible enough to enable the participationof providers of innovative, emerging services andtechnologies, or if it entrenches the existing mix of
capacity, it can also create an obstacle to innovation(Grigorjeva, 2015). The UK provides an example. While its
capacity auction is supposed to be technology neutral, newlow-carbon distributed electricity technologies are unable
to compete on an equal footing with fossil fuel generators(see Box 4) (Platt et al., 2014). New gas and diesel capacity
can access 15-year contracts in the capacity auction, but
demand side response and storage can access only 1-year
contracts. Highly complex CM design or rules may also
create a barrier to new market entrants with limited
resources to allocate to understanding and participating in
the mechanism, which is a concern with the creation of a
new market for capacity certificates in France (Box 5).

31 France targets a share of renewable energy (including hydro) in total final energy consumption of 32% by 2030 and a reduction in fossil fuelconsumption of 30% by the same year (Energy Transition Law, 2015).32 One of the 15 action points of the Energy Union reads: ‘Creating a seamless
internal energy market that benefits citizens, ensuring security of supply, integrating renewables in the market and remedying the currently uncoordinateddevelopment of capacity mechanisms in Member States call for a review of the current market design.’

Rethinking power markets: capacity mechanisms and decarbonisation 31  Box 6: Germany’s proposed system-wide approach
At the national level, Germany has surplus capacity, which it exports to neighbouring countries (BMWi, 2014).
However, its geographical variations in generation, combined with a relative lack of transmission infrastructure, leaves
some regions in Germany’s electricity market oversupplied,32 while others, particularly the demand centres in Southernand Western Germany, may face issues with power system reliability over the next few years. Variable renewablegeneration already accounts for a significant share (25%) of electricity production in the country, and this share willcontinue to grow as Germany has a target for 80% of its power supply to come from renewables by 2050. This has
required a broad national strategy to facilitate the large-scale uptake of variable renewable electricity generation.
Despite strong lobbying for the introduction of a market-wide capacity mechanism (CM) by incumbents,
including RWE and E.ON, the German Government decided to take an alternative approach. The Electricity Market
2.0 strategy, sets out plans to improve the country’s energy-only market by fostering competition between generationand other flexibility options to ‘make the electricity market fit for the 21st century’. The German Government favours
this approach over a market-wide CM as, in the words of Sigmar Gabriel, Germany’s Energy Minister, these involverisks of ‘costs spiralling out of control, government-imposed false incentives and of disruptions on the electricity
market.’ An earlier government white paper acknowledges that CMs can increase carbon emissions and ‘preserve
existing structures’ and could, therefore, ‘delay the transition and the renewal of the power plant fleet.’ In addition,
this white paper highlighted that incomplete information and uncertainties about capacity needs mean that a capacity
market would require continuous fine-tuning which would, in turn, cause regulatory uncertainty.
The proposed Electricity Market reforms33 would be the most significant since the German energy markets
were liberalised in the 1990s. The reforms are meant to enable the electricity markets to reflect scarcity value, andincentivise capacity providers and consumers to match demand and supply in the most efficient ways possible. In
all, 20 specific measures have been proposed, which include the following key elements.
•• Free price formation:34 so that scarcity value can be reflected in the market. This should incentivise market
players to invest in more flexible assets, including demand side management and storage.
•• Greater accountability of electricity providers and traders: parties that buy insufficient capacity to balance
demand and supply would face the costs of covering the shortfall.
•• Greater competition between flexibility options: measures would be undertaken to enable demand side
operators, providers of storage capacity and, in the medium to long-term, electric cars, to access the market andincrease competition between these flexibility options.
•• Redistributing the cost of grid network expansion: charges for transmission costs would be distributed
equitably across Germany.
•• An EU approach to ensuring security of supply: greater consideration would be given to security provided
through the European internal market, as this is more cost-efficient.
•• Increasing market transparency and the availability of real-time market information: with the aim of facilitating
a more efficient balancing of supply and demand.
In addition, Germany has been running a funding initiative for energy storage since 2012 and introduced a newfund to support PV battery storage systems in 2016.
The proposals outlined above to improve Germany’s energy-only market would be backed up by an extended
network reserve beyond 2017 (first introduced in 2013), a new capacity reserve, and a security standby of lignite
plants. These strategic reserves are kept out of the electricity market and will only be activated when the market
is unable to meet demand. While the wider system reforms can be applauded, the lignite security standby can be
criticised as it does not contribute to flexibility and results in targeted payments to highly polluting old coal-fired
power plants. Although the CM is framed as a tool to reduce emissions and ensure security of supply, this suggests
it may have been a political compromise to get agreement around the closure of lignite power plants by 2021.
Sources: Paulos (2015); BMWi, (2015a; 2015b; 2014); Amelang and Appunn (2015); Schwartzkopff et al. (2015).

32 This is particularly true in the north, because of significant offshore wind capacity.
33 The Electricity Market Act is due to be approved by the Cabinet in October 2016.
34 Free price formation enables prices to rise and fall i.e. through the removal price caps.

32 ODI Report4.3 Institutional risks
An analysis of experiences with CMs suggests that theirdesign and implementation involves significant additional
institutional risks. These include risks of delaying wider
market and regulatory reforms and the undermining ofregional solutions.

4.3.1 Risk of delaying wider market and regulatory
reforms
In September 2015, Margrethe Vestager, the European
Commissioner for Competition, warned that the firstfindings in the Commission’s inquiry into CMs (see Box2) suggests that these ‘are sometimes seen as quick-fix
solutions – as alternatives to real market and regulatory
reforms. If…consumers were given a stronger incentive to
respond to price increases and demand peaks, they would
reduce their consumption and there would be less needto introduce a mechanism to support peak power plants.’(European Commission, 2015h).
While some EU Member States are introducing various
tools (sometimes in an uncoordinated manner) to address
security of supply concerns (such as the UK, which
introduced two strategic reserves and a capacity auction
simultaneously – see Box 4), others are taking a wholesystems approach. Germany, for example, has undertaken
whole-market reforms alongside the introduction of its
more targeted strategic reserves (see Box 6), which can be
criticised on various grounds (see section 4.1.1.).

4.3.2 Risk of undermining regional solutions
The proliferation of national CMs across the EU risks
undermining wider EU energy market integration efforts,35
designed to improve security of supply (see Box 2). In thecontext of these efforts, the uncoordinated implementationof national level CMs undermines a regional approachto security of supply and creates an increasingly complex
regulatory environment for electricity. According to theEuropean Agency for the Cooperation of Energy Regulators(ACER), EU Member States often give little attention in thedesign and implementation of CMS to their impact on theinternal energy market and cross-border trade (Pototschnig
and Godfried, 2013). Because of electricity market
integration, however, the impacts of these mechanisms
are not limited to national borders (for a more extensive
discussion on this issue, see Baker and Gottstein, 2013).
The planned French capacity obligation scheme,for example, is likely to have cross-border impacts.
Because of the energy-only market model in Germany(complemented by capacity reserves), those suppliers thatreceive compensation for meeting their capacity obligationin France might receive double compensation throughscarcity prices when selling electricity in the Germanmarket in times of German supply shortages. Furthermore,because the costs for the capacity scheme will be borne inFrance and the capacity obligation scheme would prevent
price spikes there, German consumers can benefit fromlimited power price increases when electricity demandis high in both countries. The benefits of the scheme are,therefore, likely to accrue to French power companies
when they sell electricity in the German market with highprices and to German consumers when electricity is boughtfrom France, where prices do not reflect scarcity value.
At the same time, German capacity providers will have a
reduced opportunity to benefit from high electricity prices
in times of supply scarcity in France (DNV GL, 2015).
In addition to the technical, institutional and politicalrisks associated with the design and implementation ofCMs discussed in the previous sections, there are challenges
that are common to the design of any support mechanism(or subsidy). These include the risk of the subsidy creating
windfall profits for some market participants, and the
difficulties of removing support mechanisms once they
have achieved their objectives.
Any support mechanism risks benefiting actors that do
not contribute to the achievement of its original objectives,
or of providing premiums to actors that do not need it
to remain competitive in the market. The UK’s capacity
auction provides an example in the specific case of CMs.
While clearing prices in the first two auctions were low,
they were well above the ‘exit bids’36 of the majority ofexisting plants (Cornwall Energy, 2015b). These capacity
payments, therefore, provide additional revenues for plantsthat are already economic and would have continued tooperate also without capacity payments.
Finally, one common issue with the design of any
support mechanism (including CMs) is that once they
have been implemented, beneficiaries are likely to try tokeep them in place. In the case of CMs, the expectationsof additional revenues created by these mechanisms mightlead to reduced investments by market players when themechanism is withdrawn – which could have negative
implications for security of supply (Hogan, 2015a).
Given the uncertainties about rapid technological andwider market developments, the development of an exit
strategy is an essential element of the design of any support
mechanism. Such an exit strategy should take into account35 One of the 15 action points of the Energy Union reads: ‘Creating a seamless internal energy market that benefits citizens, ensuring security of supply,
integrating renewables in the market and remedying the currently uncoordinated development of capacity mechanisms in Member States call for a reviewof the current market design.’
36 The exit bid is the price at which a capacity provider leaves the auction – where the price is too low for the capacity provider to guarantee contributions
to future capacity.

Rethinking power markets: capacity mechanisms and decarbonisation 33  the potential adverse effects of the removal of support,
and include plans for a just transition to ensure that,when power plants are shut down and people lose theirjobs, those affected are supported (Whitley and van derBurg, 2015). Our review shows that CMs tend to support
existing high-carbon generation assets, in many cases
without sufficiently promoting much-needed flexibility.
Instead of payment schemes that entrench the status quo,measures are necessary to facilitate the transition awayfrom generation assets that do not contribute to security of

34 ODI Reportsupply or decarbonisation. In designing such programmes,
consideration should also be given to the responsibilitiesof the power sector for supporting employees (i.e. throughearly-retirement schemes and retraining programmes)
Building on wide-ranging experiences with the CMs
discussed in this section, the final section provides lessons
learned for governments that want to ensure security ofsupply while meeting objectives for decarbonisation, fossil
fuel subsidy phase-out, economic efficiency and electricity
market integration.

5 Recommendations forsupporting power market
reforms and climate andclean energy objectives
In the face of rapidly transforming power markets, linked
to the rapid uptake of renewables, there has been renewedinterest in capacity mechanisms as a tool to ensure reliability.
However, our review of current and planned CMs in the EU
and US suggests that these mechanisms risk undermining
parallel energy and climate objectives by locking in
dependence on high-carbon power generation assets.
A number of EU member states are moving ahead withthe design and implementation of domestic CMs, a processthat has been driven in part by lobbying from incumbents
in the power markets (who primarily own and operate
conventional, often fossil fuel-based thermal generation
assets). This is not surprising as these schemes can provide
a new source of stable revenues for assets that are nolonger competitive in the context of wider energy systemtransformations.
This suggests that the introduction of CMs is often
politically motivated, while the significant challenges
with their design and implementation means that there
is a serious risk that they undermine governments’parallel objectives of ensuring system reliability anddecarbonisation. The uncoordinated introduction of CMs
also risks undermining wider efforts to integrate energy
markets, which, paradoxically, are meant to ensure a more
efficient use of resources and improve security of supply.
The rapid shift towards variable renewables (wind andsolar) requires governments to reassess their approaches
to assessing and ensuring the reliability of power systems.
We find that supporting the development of secure lowcarbon and power system requires a system-wide approachthat considers continuous market developments andtechnological innovations. These efforts should recognise
the potential of demand side response, interconnection andstorage in providing economically competitive, low-carbon
flexibility. They should also include the removal of barriers
to the uptake of these technologies and consider how topromote their deployment.

The European Commission has launched a sector-wide
investigation into the development of national CMs, which
will feed into its proposals for electricity market redesignfor the end of 2016. The interim report of this investigation,
which is open for public consultation, finds that CMs havesignificant shortcomings because of inadequate assessmentsof whether they are needed at all, and exclusion of somepotential providers of capacity (such as demand side responseor storage). Nonetheless, the Commission concludes thatCMs may be necessary in specific cases.
Building on these findings, and previous research (Baker
et al., 2015; EU Commission, 2014b and 2013; Hogan
and Weston, 2014; Keay-Bright, 2013; Gottstein and
Skillings, 2012), the following section provides a numberof considerations that should be taken into account topromote power sector reforms that support not only
security of electricity supply, but also decarbonisation
objectives. These guidelines include approaches to:•• assess and understand specific security of supply issues;•• identify possible alternatives to capacity mechanisms; and•• enable the careful design of capacity mechanisms if
governments choose to implement them.
A number of these recommendations build on generalframeworks for good policy instrument design, and goodsubsidy design in particular.

5.1 Assessing and understanding securityof supply issues
When countries face issues with security of supply, it isimportant that they start with a clear understanding of thescale and the nature of the reliability challenges facing theirpower systems. This will allow governments and regulators
to better evaluate their options for market reform.

Rethinking power markets: capacity mechanisms and decarbonisation 35  

We make six recommendations as follows.
•• In their reassessment of power system reliability
issues, governments, system operators or NRAs should
consider the value of interrupted electricity supply
to consumers, and avoid setting overly conservative
reliability standards.
•• The reliability assessment should consider not only thecapacity available on the system and the capacity thatwill be needed to meet forecasted demand, but alsosystem and operational adequacy, including flexibility,
carbon intensity, transmission and distribution
infrastructure.
•• Forecasts of future demand and supply should take into
account on-going technological developments, including
improvements in energy efficiency, opportunities
for more accurate weather forecasting, demand side
response and storage technologies.
•• In addition, reliability assessments should consider
the impact of projected economic trends (such as
fluctuations in international fuel prices, or demand
trends) and the potential impact of the retirement ofexisting generating capacity.
•• The impact of planned projects and policies (subnational, national and regional) on power system
reliability should be considered. In the EU, for example,
energy market integration efforts are designed tocontribute to the reliability of power systems acrossthe region. In line with this, countries should consider
the contribution of interconnector capacity in theirreliability assessments.
•• When issues with power system reliability are identified,and intervention is deemed necessary, there is a needto set clear objectives to address the specific reliability
issues (which may not require additional capacity).

5.2 Identifying options to improve existing
market design
When an assessment of country-specific reliability issues raises
legitimate concerns, governments should consider whether
improvements in current market design can help to improve
power system reliability, and reduce the need for CMs.
We make five recommendations:•• In power markets where there are caps on electricity prices,
the removal of these caps would make it possible for themarket to provide the price signals to incentivise investmentsin the resources needed to balance demand and supply.
•• Use of time-of-use pricing in the retail market and smart
meter technologies can incentivise consumers to adjust
or shift their electricity demand in response to supply
fluctuations. This can also help to improve the reliabilityof the power system, reduce the need for back-up
generation and reduce electricity bills.

36 ODI Report•• Barriers that prevent the retirement of existing,inflexible capacity can delay the much-needed renewalof the power fleet. Countries should therefore, forexample, consider the impact of existing support
schemes for fossil, nuclear and renewable electricity
generation. These may entrench the existing power mix
and, therefore, slow the transformation to a low-carbon,
more flexible power system.
•• Efforts should also be undertaken to remove regulatory
barriers that withhold the participation of demand-side
response providers and aggregators, storage (including
through electric vehicles) and interconnection. For
example, demand-side response or storage providers
are not always allowed to participate in the wholesale
electricity market.
•• Flexibility for some power generation assets can be
improved through refurbishment. Flexibility can also beenhanced by expanding interconnection and by couplingbalancing markets (see Glossary) that can help toachieve a more efficient utilisation of existing assets.

5.3 The careful design and implementationof capacity mechanisms
After taking into account the broader actions that can help
to improve reliability, governments may still determinethat a CM is necessary to ensure security of supply. In
this case, governments should ensure that the design
and implementation of the mechanism is consistent with
objectives of decarbonisation, fossil-fuel subsidy phase out,
efficiency and affordability.
We make six recommendations, as follow:•• When a CM is implemented it should reward flexible
rather than inflexible assets to support the uptake ofvariable renewable electricity generation.
•• Given current decarbonisation objectives, consideration
should also be given as to how the CM could prioritise
low-carbon options to enhance the reliability ofthe power system (including demand response,interconnection, efficiency and storage) over highercarbon options (coal-fired power plants and diesel
generation). Similarly, consideration should be given to
how the mechanism can avoid locking in high-carbon
generation assets and support wider objectives of fossil
fuel subsidy phase out.
•• Plans to introduce CMs should always take into accounttheir potential impact on wider market reforms, while market
reforms should also consider their potential impact on CMs.
•• In the context of regional electricity market integration,
consideration should also be given to the potential
impact of the mechanism on neighbouring power
markets and how it can ensure the participation (or atleast consideration) of cross-border capacity.

•• Governments must make significant efforts to avoid
regulatory capture in the development and design ofCMs. Consultations must inform and engage a wide
range of stakeholders, so that their respective interests
and agendas can be taken into account. The timeframe
should be long enough to ensure sufficient regulatory
certainty, allowing for long-term planning, while having
sufficient flexibility for adaptation to new market
realities and technology developments. Incorporating
flexibility into the design of an intervention, througha variety of instruments or milestones for adjustment
should also help to avoid path dependency on aparticular set of technologies or approaches.
•• An exit strategy should also be developed so that theCM can be phased out when it is no longer needed.

Considering the urgent need to move towards zerocarbon power systems, governments must be held toaccount for meeting parallel objectives of decarbonisation
when they seek to address power system reliability issues.
Instead of focusing narrowly on CMs as a near-term
solution, governments should take a system-wide approachthat supports, rather than undermines, decarbonisation.
Regulators should use the opportunities provided bymarket redesign and new technologies that can add
flexibility, which will be crucial for building low-carbon,
secure power systems. As the European Commission
prepares its electricity market redesign proposals for theend of 2016, this is a key moment to influence this process,as well as the wide range of power market reforms plannedat the national and sub-national level.

Rethinking power markets: capacity mechanisms and decarbonisation 37  Annex 1: Interviewees
Dave Jones (Sandbag)
Anne-Sophie Chamoy (Energy Pool)
Michael Hogan (RAP Online)

38 ODI ReportSara Bell (Tempus Energy)
Mike Hemsley (Climate Change Committee)

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Rethinking power markets: capacity mechanisms and decarbonisation
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Cover photo: Michael Murphy(2010). Looking down from the 14th
floor of the London Transport HQ attheir recently installed solar power
panels on the 10th floor.

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