The electricity landscape is undergoing a significant transformation, becoming more complex than ever before. The transition towards a lower-carbon electricity system initiated by OECD countries is proving to be a challenging exercise, balancing trade-offs between environmental sustainability, energy security and economic competitiveness. The electricity industry is transforming, with a number of structural and disruptive changes challenging the traditional utility model. A mix of technological, economic, regulatory, environmental and societal factors is resulting in a lower carbon, digitized electricity system with new players emerging. This new landscape will be more complex and interrelated than ever before. At the same time, the International Energy Agency (IEA) estimates that an investment of $7.6 trillion through 2040 will be required from countries in the Organization for Economic Cooperation and Development (OECD). In a sector accustomed to long-term investment cycles and stable policy frameworks, this transformation introduces policy uncertainties and market design complexities. Success in the electricity sector has long been defined by ensuring a secure and reliable supply of electricity at a low cost, enabled by investment attracted to low risk, stable returns. But in the last decade, the global consensus on the importance of reducing human-made carbon emissions
has highlighted the need to also decarbonize the electricity sector, the second largest contributor to carbon emissions after transportation.
Energy policy objectives, as applied to electricity...
Energy policy today must balance affordability, security of supply and environmental sustainability. Technology is playing a critical role in the sector’s efforts to become more environmentally sustainable, providing new methods for generating power from renewable sources and new ways to use energy more efficiently. Renewable sources offer the potential to reduce emissions and, for some countries, improve security of supply by reducing dependence on imported fuel. However, these new technologies also bring new challenges. In the early stages, they cost more than the fossil fuels that they replace and require back-up, but costs decline as the technologies are deployed at scale and manufacturers gain experience. Just as significantly, the broad roll-out of renewables, with their mostly upfront capital costs and low operating costs, is changing the way that wholesale electricity markets operate. In particular, this process creates challenges in drawing investment into the conventional thermal generation sector, which for the foreseeable future will be required to provide back-up for
intermittent generation sources.
Investment in power generation has grown sharply over the past decade in markets across the OECD, rising from $60 billion in 2000 to $220 billion in 2012 – an annual growth rate of 11% in real terms. Most of the investment in generation (54%) has been in nonhydro renewables – wind, solar, biomass and geothermal – although it still accounts for only a small percentage (7-8%) of OECD energy generation. Eight out of the nine countries leading the transformation
are in Europe – with more than 10% of their power capacity coming from non-hydro renewables. Even nucleardominated France has plans to significantly increase
renewable generation over the next 15 years. In the US, the pace of change is also accelerating – 37 states have policies to encourage utilities to generate part of their capacity from renewables and 14 states already generate more than 10% of their power from non-hydro renewables. Alongside the transformation in central power sources, there has also been significant investment in decentralized generation, such as solar photo voltaic (PV) and biomass combined heat and power (CHP). These sources have taken off rapidly, particularly in some areas – for example, providing about 40% of capacity in Germany. The final set of investments has been in energy efficiency where OECD nations are becoming steadily less energy intensive, with a decline of almost 40% in energy use per
unit of GDP between 1980 and 2010.
All these investments have made a major contribution to a decline in carbon intensity of about 1% a year across OECD markets, and more in those countries that have installed a significant amount of non-hydro renewables. They have also contributed to increased security of supply by reducing the
imports of fossil fuels and exposure to volatile prices and geopolitical access risks. Imports of fossil fuels to OECD have declined by about 4% over the last 7 years. Germany is a notable exception. Despite its very significant investment in renewables, its emissions have increased since 2011 due to a switch in thermal power generation from gas to low-cost coal and the phasing out of nuclear power in the wake of Fukushima. This is in stark contrast to the US where abundant shale gas has caused the opposite shift – from coal to gas generation – contributing significantly
Electricity prices are rising...
This scale of investment has a cost for society. The
inflation adjusted price of electricity across OECD markets
increased at 2.8% for households and 5.3% for industrial
users between 2006 and 2013. Germany and Spain have
seen the steepest rises: more than 8% annually since 2006
for households and industry. Between now and 2040,
wholesale electricity rates are expected to continue to
rise by 57% in the EU and 50% in the US, due to higher
operations and maintenance and investments costs. Retail
prices are also expected to rise in real terms by 15% and
9% in the EU and US, respectively, for industrial use.
Residential electricity prices are expected to increase by
12% in real terms in the US. In the EU, prices are expected
to continue to increase until 2020 and then drop to levels
similar to today’s prices by 2040.
Subsidies for renewables have increased by about 20%
per annum for the last 6 years in the EU, and are expected
to rise about another 20% over the next 6 years. Many
factors have contributed to the increase of electricity prices,
including renewables’ support, network costs, taxes (VAT,
industrial and excise taxes) and other levies (policy support
for nuclear decommissioning, energy efficiency or CHP).
In addition to underlying costs rising, governments in many
markets still use the regulated electricity price to raise tax
revenues for activities outside of the sector such as social
costs or debt repayment. These trends exacerbate already
significant differences in industrial power prices across
developed countries, with implications for global economic
Industrial power prices in Europe, for example, are about
twice those in the US. More importantly, the differential in
gas prices between Europe and USA increased to 65%
in 2013. This difference in energy prices (partly driven by
low natural gas costs in US) is expected to contribute to a
significant decline in the market share of energy intensive
goods within high cost regions. The EU, for example, is
forecast to decrease its share from 36% to 26% over the
next 20 years. Globally, energy intensive goods account for
25% of industrial employment and 70% of industrial energy
Further investment is needed...
While the sector has come a long way in its transition
towards a more sustainable approach for generating and
delivering electricity, it still has a long way to go. Despite
investing $3 trillion between 2000 and 2012, the sector
is less than 30% of the way through – with a further $7.6
trillion required by 2040. The high level of investment seen
over the last five years will need to continue if energy policy
objectives are to be met.
Investment will be required across the board, in conventional
and renewable, centralized and decentralized capacity
($180 billion annually), and the expansion and modernization
of transmission and distribution grids ($100 billion per year).
Smarter technologies will be required to allow customers
a wider range of choices, from a more active management
of demand to the greater use of distributed generation
This level of investment would produce a system that
generates about 24% of electricity from non-hydro
renewables across OECD countries by 2040.
Although renewable generation will expand rapidly, thermal
generation plants will continue to be the key source of
back-up capacity for intermittent renewables during the next
decade until energy storage solutions become competitive
with a peaking thermal plant.
Many of the conventional thermal plants in OECD countries
are old and will need to be replaced over the next decade;
sooner in some countries like the UK. Over the next 11
years, the EU will need 138 GW of new thermal capacity to
maintain system adequacy.
Similarly, networks will also need investment both to
connect the new renewable generation and to provide
reliable, flexible back-up capacity for the intermittent
Most developed countries are incentivizing significant
investments in networks to modernize their asset base,
increase flexibility and accommodate a more complex and
However, investment is threatened by low returns...
But challenges to the viability of investments in traditional
and renewable power generation, as well as transmission
and distribution (T&D), have begun to emerge.
Average returns on invested capital in renewable generation
in Europe have declined by four percentage points from
2001 to 2013, in part because subsidies have been rolled
back in many places due to pressures on public finances.
Returns for some renewable players in North America have
also declined, but to a lesser extent.
At the same time, returns are falling for incumbent utilities
– the traditional investors in thermal and other conventional
generation. In the US, returns have also fallen about 1.3
percentage points from 2006 to 2013 due to flattening
demand and decreased load factors, despite improvements
in dark and spark spreads and lower gas prices. In the EU,
returns have fallen 4.8 percentage points from 2006 to
2013 as a result of falling demand, significant overcapacity,
reduced load factors and wholesale price declines.
For example, in Europe, demand has flattened to 0% in
2007-2012, compared to a growth rate of 2.7% annually
since the 1970s. In the US, demand has declined at 0.5%
in 2007-2012 compared to a growth rate of 2.8% annually
over the previous 30 years.
Overcapacity, caused by a lack of coordination among
energy plans designed by governments and private
businesses, also contributed to declining returns of
conventional generators. Over the past five years in the EU,
130 gigawatts (GW) of renewable capacity and 78 GW of
conventional generation have been added to the system
while only 44 GW of conventional generation has been
The shift from thermal to renewable generation – combined
with flattening demand and general overcapacity – has
led to decreased load factors by as much as 30% in Italy
and Spain since 2006. Competition for the remaining load
increased, with spark spreads falling to as little as 5% of
their 2009 values in Italy. In contrast, power generators in
the US have preserved their profit margins as capacity has
remained more balanced, with retirement of old plants more
closely matching new build of renewables and dropping fuel
In many European markets, returns on conventional thermal
plants are no longer high enough to justify the capital
expenditure to replace them.
T&D is marginally more immune to the factors that are
driving down returns because networks are a longer
term, regulated asset business. However, decentralized
generation raises questions about the traditional economic
model for T&D businesses. As customers substitute locally
generated electrons for those from centralized power plants,
load on the grid falls and grid operators are forced to raise
prices on the remaining units to recover their fixed costs.
Rising T&D charges create a greater incentive for local
generation, creating a downward spiral. If investment is to
be maintained, new remuneration systems will be required
that better value reliable grid capacity and the evolving role
of network operators.
Lessons from first movers on the root causes of investment challenges...
The EU has moved towards renewables ahead of other
OECD nations, offering valuable lessons in three areas:
policy design, market design and business models.
Policy design. Society recognizes the need for an
electricity system that produces less carbon, but has not
yet fully bought into the full value of decarbonization. This
creates a gap between society’s desire for renewables
and its willingness to pay for them. Although the falling
cost of renewable technologies is helping to reduce this
gap, additional efforts are required to promote the value
to society from reductions in emissions. For example, a
2013 survey conducted by Swiss Re found that across 19
nations, individuals were unwilling to pay more than 2%
extra on their energy bills for renewable energy on average,
despite a desire for increased decarbonization. This gap
leads to policy instability, which drives up those same costs
by increasing investor uncertainty and cost of capital
It is important, therefore, for policy-makers to incentivize
investments that help minimize or avoid unnecessary costs.
The EU’s experience as a “first mover” provides valuable
For example, it is obvious to most European citizens that
southern Europe has the lion’s share of the solar irradiation
while northern Europe has the wind.
But the EU’s investment in renewables does not reflect this:
where Spain has about 65% more solar irradiation than
Germany (1750 vs 1050 kWh/m2), Germany installed about 600% more solar PV capacity (33 GW vs 5 GW). In contrast,
whereas Spain has less wind than countries in the north, it
has still installed 23 GW of wind capacity.
Such suboptimal deployment of resources is estimated to
have cost the EU approximately $100 billion more than if
each country in the EU had invested in the most efficient
capacity given its renewable resources. And by looking
across borders for the optimum deployment of renewable
resources (with associated physical interconnections), the
EU could have saved a further $40 billion.
Policy design issues contributed to this costly outcome,
including the desire within EU states to maintain national
sovereignty over energy policy, a lack of integrated planning
and interconnection between EU markets, and particular
market design issues such as uncapped solar incentives in
Given the misalignment between society’s desire for
decarbonization and its willingness to pay for the perceived
benefits, policy instability has been seen across many
countries, particularly in support for renewable incentives.
Renewable incentives will continue to be important over
the next decade, particularly for those technologies that are
still at an early stage of development and require support
to deploy at scale and drive down costs with increased
experience. Combined subsidies for renewables in the
EU, US and Japan are forecast to rise from $99 billion per
annum to a peak of $136 billion per annum by 2025.
In some countries, however, the financial crisis and other
economic concerns have caused policy-makers to reevaluate
their subsidy regimes. This kind of policy instability
deters investors and further raises the cost of capital of
investment. In some cases, this has caused forward looking
subsidy budgets to be scaled back. For example, in the
US, there are uncertainties in the renewal of tax credits for
renewables, and for carbon taxation in Australia.
In other cases, governments have made retroactive changes
to subsidy policies. For example, in 2013, Spain effectively
removed subsidies on wind capacity installed before 2005
and scaled it back on wind farms installed between 2005
and in 2008. Portugal, Greece and other European countries
have also made retroactive changes to renewable subsidies.
Market design. Electricity markets across developed
economies have deployed nearly every flavour of market
design, from the liberalized markets that prevail in the UK, Australia and New Zealand, to the more highly regulated
models found on the West coast of the US and in Japan.
No single type of market presents the right answer for
every economy. Liberalized markets can succeed as long
as policy-makers ensure very clear signals through market
mechanisms to encourage industry participants to invest
behind society’s policy goals. In more regulated markets,
policy-makers have more direct control, but efficiency
depends on making the right policy and technology choices,
providing stability in policy and being vigilant in agreeing
Regardless of the regulatory positioning, all regulators
must recognize that balancing environmental stability and
affordability against security of supply requires that they
ensure clear, effective signals on carbon pricing, reliability
and flexibility, networks and other market mechanisms.
The experience of recent years suggests that current
electricity markets suffer from a lack of effective market
mechanisms, particularly in regard to carbon pricing. The
existing carbon pricing mechanisms are conceptually simple,
but politically and practically complicated to implement. The
EU Emissions Trading System (ETS) failed to deliver a cost of
carbon sufficient to drive adoption of renewables – the price
of carbon falling from about €30 per tonne in 2008 to €5 per
tonne in 2014, well below the 2020 target price of €25 per
tonne, and a Market Stability Reserve is to be introduced.
Overlapping renewable targets and the economic downturn
likely further exacerbated this outcome.
In the generation part of the value chain, the increasing
penetration of low marginal cost and intermittent renewables
in Europe has lowered wholesale prices and raised the
debate over whether “energy only” markets can ensure
reliability without interventions. Policy-makers and regulators
need to find a way to signal the need for new investments
by appropriately valuing reliability and flexibility.
Without these clear signals, policy-makers risk shortfalls in
electricity supply. For example, in the UK, low returns led to
a predicted short-term shortage of capacity as older plants
were retired. This has forced the regulator and system
operator to step in and introduce a competitive capacity
market (paying generators to maintain available reserves of
electricity capacity) to improve the reserve margin in 2018-
The uncapped renewable incentives and the lack of
an integrated plan across renewable and conventional
technologies have also resulted in capacity overbuild in
some countries. And this overcapacity can be exacerbated
when state or national governments intervene to support
particular technologies for the purposes of local industrial
activity — where costs may be too high without either the
right competitive advantage in the renewable resources or
R&D and manufacturing expertise.
In Spain, renewable generators installed 26,000 MW of
capacity between 2005 and 2010. Over the same period,
nearly 11,000 MW of traditional combined-cycle gas
turbine (CCGT) capacity was installed by businesses that
overestimated demand and underestimated the ability of
renewable technology to meet the energy plan’s objectives.
Consequently, the CCGT plants must now reduce capacity,
for which the government plans to provide compensation
which, in turn, raises the price of electricity.
In transmission and distribution, decentralized generation
has reduced the load on the grid and net metering tariffs
have disrupted traditional economics. Although net
metering can provide effective incentives for investment in
decentralized generation, it does not appropriately reflect
the value and cost of the required grid connection. At the
same time, traditional regulation of distribution networks can prevent the deployment of innovative technologies and
business models such as smart grid solutions and demandside
management. Thus, effective market design must also
include appropriate signalling and pricing for decentralised
Overall, market harmonization of generation and T&D
across countries also remains a challenge for regulators,
creating inefficiency and resulting in an uneven playing
field for energy-intensive industries and a slow pace of grid
interconnections between countries. The opportunity in
increasing harmonization, encouraging appropriate physical
interconnection and removing unnecessary regulatory
barriers to competition is large.
In the UK, National Grid estimates that each gigawatt of new
interconnector capacity could reduce Britain’s wholesale
power prices by as much as 2%. In total, 4 –5 GW of new
links built to mainland Europe could unlock up to £1 billion of
benefits to energy consumers per year, equating to nearly £3
million per day by 2020.
Business and investor models. Significant transitions in
other industries offer many lessons about the opportunities
and risks to existing business models in the power
sector. During the shift from fixed-line to wireless mobile
in the telecom industry, for example, many incumbent
telecommunications companies moved slowly because
they feared cannibalization of their core business, were
prevented by regulations from participating or simply lacked
the capabilities to take full advantage of new opportunities
in mobile. Some of the firms that successfully adapted spun
off new businesses which were able to move at a faster
pace and often under different regulations. In that transition,
incumbents were able to capture some of the gains from
new products and services, but much went to new and more nimble players who had the capabilities required to
succeed in mobile communications.
If anything, the energy transition driven by both
decarbonization and technology innovation promises
an even more startling shift. Customers – once merely
consumers at the receiving end of long lines of transmission
and distribution wires – are, in some cases, now generators
themselves. And even if they are not generating or storing
their own energy, they will certainly participate more actively
in choosing their supply sources and controlling their
demand. This will encourage the development of more
customer-centric business models and technologies.
New business and investment opportunities are therefore
arising, particularly at the customer end of the energy value
chain, for example, in distributed generation, demand-side
management, energy efficiency measures and electrification.
Policy-makers can encourage these new, higher risk
ventures with the right kinds of incentives.
For example, solar has spurred a whole set of new
businesses in which companies work with individual
consumers to create an end-to-end proposition: providing
low cost solar energy and coordinating all the investment
flows on behalf of the customer.
Energy service businesses also have emerged to support
customers in installing and maintaining their own heat and
power networks. Technology companies are showing much innovation in energy efficiency and support for demandside
response in businesses and consumers, respectively.
Innovation is happening on the supply side too, with
financing for plant upgrades that can improve efficiency in
existing plants. And network equipment companies have
created “virtual networks” of decentralized generation and
consumption to optimize system efficiency, increasingly
employing big data technology to manage the complexity.
As in the transformation of the telecom sector, much of
this innovation comes from new companies entering the
electricity sector, excited by the opportunities offered by new
technologies. Incumbent utilities, like their landline telecom
counterparts, have often been inhibited by regulatory
constraints or lack of relevant capabilities. But there are
signs that some incumbents are developing the necessary
capabilities, either through separate subsidiaries or by
acquiring and growing businesses.
Contrary to some other countries where the development of
renewables has been led by utilities, in Germany incentives
on renewables attracted an entirely new set of investors.
The majority of the investment (more than 80%) was from
non-traditional investors – individuals, new developers,
sovereign wealth funds – rather than incumbent utilities.
Much of the investment was targeted at decentralized
energy, closer to the customer, which is indicative of the
types of business models required to be successful in this