Electricity markets covering large geographic areas are needed to accommodate the deployment
of wind and solar power at least cost. Renewables need to be harvested and transported via wire
over vast territories. Their output does not follow consumption. It depends on variable wind, sun
and exogenous conditions that are difficult to predict. Given the limited and relatively expensive
options for storing electricity, it is less costly to integrate variable renewables when tapping into
the flexibility of electricity systems over wide areas.
Electricity markets in some regions are under strain. Perhaps the most salient phenomenon in
Europe is that gas-fired power plants in markets with overcapacity are not competitive, despite
the fact that they will be needed to complement renewables and replace ageing capacity. Another
issue is the use of state-level renewable energy support schemes. Not only do these not use power
markets to drive investments, they also undermine their functioning. The cost of renewables support
can seem very high compared with the cost of measures to support conventional generation and
ensure supply security. Yet falling back on some form of fragmented state regulation should not
be seen as a reasonable solution to decarbonisation.
Reaping the benefits of market integration is vital to enable renewables deployment and control
costs. The cost of renewable energy policies is a growing concern. Hence, decarbonising at least
cost requires tapping renewable and flexible resources over large geographic areas. Large markets
are essential to efficiently co-ordinate the growing number of generators and consumers. Recent
studies have quantified the potential benefits of market integration in Europe at EUR 12.5 billion
to EUR 40 billion per year, or a medium value of EUR 6.8/megawatt-hour (MWh) of consumed
electricity (Booz, 2013). Similarly, PJM Interconnection LLC (PJM) claims that more efficient operations
save USD 2 billion annually, or USD 2.7/MWh.
The question, therefore, is where and how governments can work together to reap the full benefits
of power market integration.
Renewables deployment calls for more efficient integration of real-time markets. Currently, the
rapid deployment of wind and solar power creates bottlenecks in networks and unscheduled loop
flows among adjacent grids. This tends to limit the network transfer capacity (NTC) available for
cross-border trade. Looking ahead, managing variability of renewable energy, for instance
between the sunny Mediterranean Sea and windy North Sea regions, will become necessary. A
successful integrated electricity market should not only cover wide geographic areas, but also be
flexible, demonstrating its ability to cope with changing weather conditions and unpredictable
power flows while ensuring electricity security.
Cross-border electricity trade continues to be perceived as potentially risky to electricity security.
Indeed, it must be acknowledged that all the recent blackouts – Italy and New York in 2003,
Western Europe in 2006 and India in 2012 – were due to a lack of co-ordination among system
operators. System operators are inherently conservative – which is legitimate when deploying wind
and solar power in electricity systems designed for conventional power generation technologies
such as gas, coal and nuclear power plants. Furthermore, growing imports tend to be seen as
risky in some jurisdictions where governments’ first priority is not market integration, but
“keeping the lights on”.
Based on the experience of International Energy Agency (IEA) member countries, this paper can
identify two ways to integrate markets over wider geographic areas:
• First, consolidate markets and system operations. The most direct way is to merge system
operators, ensuring that the same rules for electricity system security apply across all consolidated
control areas. The National Electricity Market (NEM) in Australia and PJM and MISO in the
United States illustrate the higher efficiency of this approach. To date, consolidation has
created large control areas spanning several states within a country (intra-country), but not
among countries (inter-country).
• Second, co-ordinate markets and system operations. When consolidation is not possible, co-
ordination remains necessary between adjacent system operators. This approach requires defining
cross-border transmission capacity and ensuring efficient price formation at the border. It
also requires a co-ordinated adequacy assessment and management of emergency situations.
The more efficient the co-ordination, the more likely the outcome of a consolidated system
and market operations.
The consolidation approach is more suited to real-time market integration in highly meshed
networks. In principle, this can ensure more efficient, dynamic and flexible use of existing assets
for real-time markets. Consolidated system operators can better avail themselves of physical
transmission capacity and handle network congestions. This is particularly relevant in highly meshed
networks. In electric islands or peninsulas with limited physical cross-border lines/interties, separate
system operators with different price zones may remain the best practical solution.
A key finding of this report is the need for strong co-ordination of electricity security regulatory
frameworks. Electricity security lags behind market integration. The lack of co-ordination of reliability
standards is limiting further progress. Without a clear, common and sound regulatory framework
on electricity security, markets cannot deliver the right price signals during scarcity conditions or
provision the necessary flexible resources to complement variable renewable energy (VRE) or signal
where investments should be made. Hence, the electricity security regulatory framework needs to
be harmonised − or better yet, standardised − over the relevant geographic area of an integrated
market.
Several barriers hinder the efficient integration of electricity markets. The physical explanation
is the lack of transmission lines to interconnect markets in some areas. Even where transmission
lines do exist, they are not always used efficiently. Other barriers are institutional. Electricity
security remains a concern, and local government and regulator mandates are set at the national
(e.g. in Europe) or state level. Finally, the distributive impacts of market integration should be
addressed, as they will otherwise remain a barrier.
Addressing barriers to integration of electricity markets requires actions at the three levels of
policies, regulation and markets. Governments have an important role to play, along with regulators
and system operators. Federal or international organisations can overcome some barriers, while
bilateral or multilateral governmental frameworks can address others with bottom-up initiatives.
Regulators and system operators can also play a decisive role (e.g. with market coupling in Europe).
Policies
Power markets do not integrate by themselves. A policy commitment is needed to create
efficient markets over large geographic areas. Governments must work together – and with
international organisations – to ensure reliable, affordable and clean electricity in the relevant
geographic area. The mandates of independent regulators and system operators should also be
aligned with these policy objectives. Integrating markets requires functional, liquid and
competitive wholesale markets, which in turn calls for a strong commitment towards electricity
market liberalisation at the political level.
Policies pertaining to the security of the electricity supply are either national (in Europe) or the
responsibility of states or provinces (in North America and Australia). They include many
dimensions, such as defining reliability targets (in terms of loss of load expectations [LOLE]) and
attaching value to reliability in the cost-benefit analysis of investment decisions. Their more
technical aspects include devising binding security standards for network construction, as well as
protocols for use in scarcity conditions and load curtailment procedures across jurisdictions.
Efforts to harmonise the regulatory frameworks for electricity security lag behind efforts aiming
at market integration. To a certain extent, policy integration implies transferring competence for
supply security, which might explain the slow progress to date.
Low-carbon generation and renewables are now an integral part of many electricity systems
and are probably the most promising field for further integration. An integrated approach can
bring significant benefits over renewables policies for countries or individual regional governments.
Evidence shows that despite its effectiveness, today’s patchwork of policies across borders has a
high cost and is visibly impacting on end-user prices. As renewable technologies mature, low-
carbon policies need to be included in the scope of the market integration project.
Interconnectors
Interconnector services constitute the backbone of electricity market integration. Yet the interface
between system operators very often constitutes a barrier to cross-border trade. The major issues
found at this “seam” between the control areas of adjacent system operators include planning,
construction and cost allocation of new transmission lines, the reliability implications of cross-
border power flows of adjacent system operators and practical difficulties in making the best use
of existing interconnection capacity.
Transmission lines that connect markets can already be well developed within synchronous
frequency areas. Cross-border lines amount to 11% of installed generation capacity in Europe –
ranging widely from only 3% in Spain and the United Kingdom to 48% in Switzerland (a key
European country whose electricity flows are influenced by international trade). In the United
States, the Western and Eastern Interconnections are poorly linked, with only 2 gigawatts (GW) of
capacity for an installed system capacity exceeding 900 GW.
Reliability is the first preoccupation of governments, regulators and system operators. Recent
security events in synchronous areas remind us of the fundamental physical reality of electricity
grids. With the deployment of renewables, power flows will become more volatile from one hour to
the next, or over even shorter timeframes, creating electricity flows that cannot always be correctly
anticipated. Some system operators have created embryonic common control rooms to improve
co-ordination in real time. Deeper market integration, including wind and solar power, would require
more exchange of information in real time and better co-ordination of network operations.
Interconnectors are not always the least-cost solution. Ensuring system adequacy can result in a
mix of solutions blending capacity generation, demand response, storage and new transmission
and distribution infrastructures.
Building new interconnectors requires co-ordinated planning, regulation and siting on a comparable
cross-border area. The long and burdensome licensing and siting procedures are further compounded
by the challenges to creating a co-ordinated investment framework, leading to concerns about the
slow development of interconnectors. Should the licensing process be streamlined, new interconnectors
would still encounter local opposition and costs that could constrain interconnector capacity. It is
vital to create an open network development framework to take advantage of competing market
and technological solutions.
The cost allocation of new transmission lines must reflect the benefits. The lack of agreed cost-
allocation methodologies can hinder investment, since greater interconnection normally creates
both winners and losers by lowering prices in one area while raising them in another.
While identifying and allocating the available interconnector capacity of existing assets can prove
effective, this exercise is often neglected. Its main tasks include: (i) applying dynamic and close to
real-time capacity assessments that accurately reflect the physical network and system reality
with high spatial resolution; (ii) removing any cross-border access charging of infrastructure costs
that do not represent costs of network use across the integrated market; and (iii) allocating the
transfer capacity over different time horizons (i.e. long-term, forward, intraday, balancing and system
services timeframes). Transmission rights should be allocated dynamically and competitively,
especially in regions with growing dynamics from variable renewables generation. But trading
closer to real time reinforces the need to closely monitor system security.
Governments and regulators play a very important role, as they establish and amend sound
policies, regulatory frameworks and institutions. These dimensions influence electricity reliability,
as well as market participants’ use of existing assets for different services at different times and
locations and the efficiency of renewables integration. Stronger dedication to inter-regional
approaches and sufficient responsible staff at all institutions will facilitate reliable and efficient
regional market integration.
Markets
There is clear empirical evidence that consolidating system operations over wide geographic
areas can lead to significant changes in power flows – an indication of a more efficient dispatch,
in particular in areas with locational marginal pricing. The most famous examples are the
establishment of the NEM on Australia’s east coast in 1998 and the expansion of the PJM
footprint since 2000 to a large portion of the Northeast Interconnection. Other opportunities to
merge system operators and their balancing areas may exist in Europe, North America and Japan.
In any event, co-ordinating energy markets at the interconnection seam is a necessary step.
Poor co-ordination sometimes leads to energy trades in the wrong direction, i.e. from higher-price
zones to lower-price zones. Among the solutions available to co-optimise networks and generation,
day-ahead market coupling – already implemented in parts of Europe – ensures efficient use of
interconnector capacity and has proven successful at eliminating such inefficient trades on the
day-ahead timeframe. These trades are, however, more difficult to eliminate for intraday and
close-to-real-time pricing, as witness the cases where real-time prices diverge significantly from
day-ahead prices. Inefficient trades usually result from administrative time lags between system
operators that schedule cross-border transactions before knowing the real-time prices.
Balancing energy and ancillary services will likely grow to compensate for the variability and
uncertainty of wind and solar power. These services are traditionally subject to regulation and
operated by system operators within their control area. Two leaders in renewables deployment,
Germany and California, have recently procured balancing services in adjacent control areas.
Several plans are under way to extend them, including the Agency for Cooperation of Energy
Regulators (ACER) Framework Guidelines, the European Network of Transmission System Operators
for Electricity (ENTSO-E) Network Codes on Balancing and Ancillary Services and the Energy
Imbalance Market proposed by the California Independent System Operator (CAISO) in the Western
Interconnection of the United States. The key question here is, will each balancing area retains control
over real-time dispatch instructions or will a single system operator control the integrated system?
Forward and financial markets also need further development to provide a hedge against cross-
border electricity trades. Selling electricity across borders may expose traders to hard-to-predict
volatile price differences when interconnector capacities become scarce. Financial products such
as financial transmission rights (FTRs) or contracts for difference (CfDs) offer more opportunities
to trade long-term contracts across borders, thereby increasing competition. When physical contracts
do exist, they should contain provisions such as “use it or sell it” to ensure they match financial
contracts in terms of efficiency of capacity use. Independent service operators (ISOs)/regional
trade organisations (RTOs) and power exchanges may need to play a more active role in
establishing and maintaining enough liquidity for FTRs.
Burgeoning capacity mechanisms raise many co-ordination problems. Fragmented and inconsistent
capacity constructs as varied as capacity payments, strategic reserves or capacity markets risk
undermining the functioning of integrated energy markets. While allowing cross-border capacity
trade would improve the situation, it faces many obstacles, mainly stemming from the absence of
integrated electricity security policies and regulations. The proposed principles for ensuring co-
ordination of capacity markets are:
• integrated generation adequacy forecasts;
• harmonised capacity product definition;
• joint determination of cross-border capacity transfer capability; and
• adaptability of capacity markets to future harmonisation efforts.
Differences in low-carbon policies, including different CO2 taxation and national carbon prices,
distort integrated wholesale electricity markets. For instance, carbon prices applicable in one
jurisdiction but not in another can lead to carbon leakage and imports of electricity with a higher
carbon content. In the absence of a comprehensive energy policy, the patchwork of local clean
policies inevitably reduces the efficiency of integrated electricity markets.
Building on the positive experience of integrated pools and coupled markets, the next step in
achieving integration requires common intraday, balancing and capacity markets and harmonised
carbon policies to cope with new challenges and enhance the efficiency of energy transitions and
renewables integration.