COMMISSION STAFF WORKING DOCUMENT Energy prices and costs report
Date: 2014-01-22
Institutions: European Commission
Subjects: distribution cost, electrical energy, electricity supply, natural gas, price net of tax, price of energy, production cost, tax, trans-European network













EUR-Lex - 52014SC0020 - EN











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52014SC0020

COMMISSION STAFF WORKING DOCUMENT Energy prices and costs report /* SWD/2014/020 final */









Table of Contents
Introduction. 2
1.      Energy prices in the EU.. 3
1.1.              Developments
in the retail markets for electricity. 8
1.1.1.         Electricity retail price developments
by components. 14
1.1.2.         Electricity price developments in
selected industries. 44
1.2.              Developments
in the retail markets for natural gas. 70
1.2.1.         Natural gas price developments by
components. 75
1.2.2.         Natural gas price developments in
selected industries. 100
1.3.              Chapter
conclusions. 119
2..... Energy costs in the EU.. 122
2.1.              Household
energy costs. 123
2.2.              Industry
energy costs. 131
2.2.1.         Identifying energy intensive
industries. 131
2.2.2.         Energy costs evolution. 136
2.2.3.         Energy costs in selected energy
intensive industries (EIIs) 142
2.3.              Chapter
conclusions. 163
3.      Energy prices in a global context 164
3.1.              Global
energy commodity and wholesale prices. 164
3.1.1.         Crude oil, coal and uranium.. 164
3.1.2.         Natural gas. 167
3.1.3.         Electricity. 173
3.2.              International
comparison of retail prices of electricity and gas. 175
3.2.1.         Electricity retail prices. 176
3.2.2.         Gas retail prices. 178
3.3.              Retail
price evolution. 180
3.4.              Retail
price composition: examples. 182
3.5.              Energy
taxation. 185
3.6.              Energy
price subsidies. 187
3.7.              Energy
and cost competitiveness. 188
3.8.              Chapter
conclusions. 200
4.      Future high energy prices
in the EU: macroeconomic consequences. 203
4.1.              Scenario
Description. 204
4.2.              Modelling
results. 214
4.3.              Chapter
conclusions. 223
Annex 1. Electricity and
gas price evolution: results by Member State. 225
Annex 2 Methodology for a
bottom up analysis of industry sectors. 229
Annex 3. The merit order
effect 234
Annex 4. International
comparison of prices of electricity and gas paid by a sample of EU producers  236
Annex 5. Vulnerable
consumers. 242
Annex 6. Short description
of the GEM-E3 model 244

Introduction

Europe's energy
sector is in the midst of a major transformation. Its gas and electricity
sectors are moving from public monopolies into competitive private companies in
liberalised markets and electricity generation is being decarbonised, with strong
growth of wind and solar power in particular. At the same time, alternative gas
supplies are being developed and diversified and the transport sector is
becoming more fuel efficient and starting to use cleaner, alternative fuels.
There are
different expectations and understanding of how all these changes affect each
other. The liberalisation of the market is expected to deliver more competitive
and therefore efficient and cheaper energy; environment and climate policy and
decarbonisation is meant to ensure a sustainable energy sector for the long
run, with acknowledged short term costs. Governments expect such changes to
deliver short term benefits to consumers as well as longer term sustainability
objectives. And the energy industry itself has to adapt to very different
environmental, commercial, regulatory and technological regimes.
These efforts
of Member State governments to create a more competitive and sustainable energy
sector coincide with a major economic downturn in Europe's economic activity.
Such economic hardship often triggers reluctance to change, and this is
becoming visible in the energy sector: measures to protect jobs and enhance the
competitiveness of national industry are impacting market liberalisation; the
affordability of the short term costs of achieving sustainability is
questioned; reliance on existing market players, structures and technologies
grows heavier. 
In light of
such questions of the high costs to consumers and reduced European
competitiveness, it is important to scrutinise and analyse the details of what
is happening in the energy sector. There is a need to ensure that the changes
and transformation underway are not undermining Europe's competitiveness, and
that competitive and cost effective solutions are sought out to minimise
negative impacts. This is why the conclusions of the 2013 May European Council
announced a forthcoming analysis from the Commission on "the
composition and drivers of energy prices and costs in Member States (…), with a
particular focus on the impact on households, SMEs and energy intensive
industries, and looking more widely at the EU's competitiveness vis-à-vis its
global economic counterparts"
This report has
been produced to support such scrutiny. Chapter 1 starts with a review of
recent trends in energy prices and breaks down energy prices to explore the
trends in separate price drivers (the electricity or gas costs, network and
taxation elements of retail prices). The relationship between wholesale and
retail prices is examined for gas and electricity markets and the consequences
of regulating household and industrial consumer prices  is examined. Chapter 2
looks at the impact and the evolution of energy costs, comparing household and
industry costs across time, different industry sectors and Member States, with
aggregated data and with case studies[1].
Chapter 3 provides international comparisons of energy prices and costs,
looking at disaggregated prices and comparisons of taxation in particular, and
explores the global nature of some hydrocarbon markets compared with the
regional markets of natural gas and electricity. Chapter 4 examines the
possible macroeconomic and sectoral consequences of ongoing European
cost increases.

1.                                    
Energy prices in the EU

Key global energy commodity prices have increased
in recent years, including oil and coal. However in the global markets for oil
and coal, prices move in step and energy consumers across the globe pay broadly
the same price. So price differentials - that can raise costs to consumers and
generate competitive advantages or disadvantages – are not a concern. That is
why these two fuels and the transport sector are not covered extensively in the
report. 
However in gas and electricity markets,
despite a degree of global tradability of fuels and equipment (such as wind
turbines), there are at best regional prices, and more often national or sub
national prices, which change retail costs and prices for consumers and can
generate inefficiencies or competitive disadvantages in what should be the
single market.
The figure below presents a diagram of the
basic elements of the final electricity and natural gas bills. All components
and subcomponents listed below contain many elements that cover costs incurred
by economic agents along the value chain on the one hand and financial charges
and exemptions imposed upon taxpayers by the legislative authority of Member
States on the other.
To a certain extent, the electricity and
natural gas sectors operate under comparable industrial structures as both are
fairly capital intensive, deliver energy products which are often used as
inputs by other businesses, and rely upon a complex grid structure to ship the
product from generators / extractors to final consumers (thus both are referred
to as “network industries”). The similar industrial features explain to a large
extent the similarity of the first and second tier elements of the end consumer
bill. Yet, looking into more detail, differences start to emerge.
Figure 1. Schematic break-down of an end consumer
bill for electricity and natural gas
The wholesale
element covers the costs incurred by companies to deliver the energy
product on the grid. 
In the case of
natural gas, it covers the costs of production and processing of domestic
hydrocarbon resources or the costs of acquisition of imported gas which contain
those elements plus costs related to shipping to a delivery point on the high
pressure system. 
In the case of
electricity this element covers direct costs related to the construction, operation
and decommissioning of electricity generating units which can further be broken
down to capital expenditures, (CAPEX) - which includes for instance overnight
costs[2],
capital costs, liability insurance and decommissioning - and operating
expenses, (OPEX) which includes for instance costs of operation, maintenance,
refurbishment, fuel and carbon as well as costs related to the operation of
wholesale trading activities.
A robust
competitive market, as foreseen by the IEM legislative packages[3], ensures that the
optimal available mix of assets and suppliers is used to deliver the energy
needed by end consumers in the most cost efficient manner.
The retail
element covers costs related to the sale of energy products to final
consumers, including (but not limited to) portfolio management (size and
structure of client base), personnel, IT, overheads, insurance for imbalance,
etc.
The transmission
and distribution elements can be similarly broken down into CAPEX- and
OPEX- related components which include infrastructure costs (maintenance and
grid expansion), system services (costs by use or by availability), network
losses and other charges such as (but not limited to) stranded costs, public
service obligations, policy support to certain technologies, etc.
Finally, the elements
related to taxation policy can be grouped along several criteria to two or
more sub-categories. 
From the perspective
of the taxpayer, the tax-related elements can be broken down into recoverable,
partially recoverable and non-recoverable parts. Recoverable taxes or levies
include full or partial recovery of taxes paid on purchases, either as a
payment or as an offset against taxes owed to the tax authorities. VAT is an
example of a recoverable tax but there may be more such taxes and levies which
may be imposed on different administrative levels (local authorities, regions,
states, federal authorities etc.). Partially recoverable taxes include a
combination of taxable and exempted levels of consumption. In the case of
non-recoverable taxes or levies, the full amount of collected proceeds is
transferred to the tax authorities. This distinction is important when it comes
to retail prices for different types of final consumers of electricity and
natural gas. For example, the tax-related elements for households would most
often be non-recoverable whereas at least some part of the taxes and levies companies
that are paid by companies would be recoverable and companies may further
benefit for some special exemption regime.
When it comes
to the destination of the proceeds collected, the third part of the consumer
bill can be broken down by taxes, which are unrequited
payments to finance the general public budget, and charges/levies, which are
ear-marked to different energy or other policy measures.
Different
taxes, levies, non-tax levies, fees and fiscal charges include value added tax
(VAT), concession fees, environmental taxes or levies, other taxes or levies
linked with the energy sector (such as public service obligations/charges,
levies to financing energy regulatory authorities, etc.), other taxes or levies
not linked with the energy sector (national, local or regional fiscal taxes on
energy consumed, taxes on gas distribution, etc.). As specified in Directive
2008/92/EC, taxes on income, property-related taxes, oil for motor cars, road
taxes, taxes on licences for telecom, radio, advertising, fees for licences,
taxes on waste, etc. are excluded from the taxation element and included in
energy and supply because they are part of the operators' costs and apply also
to other industries or activities.
It should also
be noted that the break-down in Figure 1 is schematic and that in reality
policy support measures may appear in different parts of the electricity or
natural gas bill, including the energy, network and taxation parts. One example
of such measure that will be looked at in greater detail is the policy support
measures that were put in place by Member States to reach the 2020 targets on
climate change and energy sustainability.
Methodological
issues
Most of the
analysis of Chapter 1 concentrates on the evolution of the different components
of the end consumer bill from a top-down perspective, based on
harmonized collection methodologies over broad segments of the economy which
were identified by the level of energy consumption rather than by industrial
sectors or specific groups of household consumers. 
Special
attention is given to prices for household consumer bands DC (electricity) and D2
(natural gas) as these are the median bands with the highest number of
electricity and gas consumers in the majority of Member States[4]. For the industrial
sector[5],
the focus is on the medium price data for bands IC and I3 as those groups
typically represent medium size enterprises. As such, DC and IC (electricity)
and D2 and I3 (natural gas) are the most representative consumer bands.
The prices
reported in this and following Chapters cover the period from 2008 to 2012 as
these are the first (and respectively the last) full year with complete retail
price data for all MS and under the new Eurostat methodology at the time of
drafting.
The top-down
price developments inform mostly on general developments. The specific,
on-the-ground conditions can be quite different from these developments,
especially for the energy intensive industries. For example, companies can
operate under special regimes, pay or be exempted from extra taxes or levies
(ETS), be subject to a special state aid regime etc.
The current
legal basis for data collection on retail prices for electricity and natural
gas does not allow for a detailed breakdown of costs related to energy, network
and taxation[6].
In addition, there is no harmonised methodology specifying under which category
– energy, network or taxation - Member States should attribute costs related to
specific public policies. 
The main
purpose of a bottom-up assessment of the evolution and composition of energy
prices and costs at the level of individual industry sectors and plant level is
to complement the information already available at a macro level with a
fundamental bottom-up perspective on the operating conditions that industry
stakeholders need to deal with. Section 1.1.2 and section Error! Reference source not found. provide
price assessments for electricity and natural gas prices for a select group of
European industries based on a methodology which is described in Error! Reference source not found.. 
Retail price
trends
Figure 2 presents electricity and natural gas prices for the median
household consumer bands expressed in Euro per kWh of energy. The remaining
sections of this chapter provide a detailed analysis of the various components
of retail prices. Figure 2 illustrates
the variation of price conditions across Member States ("price
dispersion"). 
A similar
pattern seems to apply: the ratio of highest to lowest price in the Member
States is in the range of 4 – 2.5 to 1. Similar ratios are observed for all
energy products (electricity or gas); consumer types (domestic or industrial),
consumer bands (modest, median or big consumers), monetary units (Euro,
national currency or purchasing power standards[7])
and periods (2008 - 2012). 
Despite efforts
towards the creation a single EU market for energy, retail price conditions
remain persistently different across borders. This development contrasts
sharply with what is observed in the wholesale markets for electricity and
natural gas where the major benchmarks are broadly aligned. A combination
of factors could explain why the introduction of market mechanisms has proved
to be more difficult in the retail segment. These are further discussed in Sections
1.1.1.1 and Error! Reference source not found.. 
Figure 2. Retail prices for electricity in
EUR
To indicate the
degree of divergence of the prices of electricity and natural gas in the EU, Table 1 provides dispersion metrics of price
levels for a variety of markets and illustrates that price dispersion remains
high in electricity and natural gas. 
In 2012 the
dispersion - measured as standard deviation divided by mean - was about 0.30 in
the case of retail price of electricity and gas (including taxes in the case of
households and excluding VAT and recoverable taxes in the case of industry), while
it was below 0.1 in the case of motor fuels (including taxes). The variation
coefficient for total labour costs stood much higher, at around 0.6.
While the
levels of price variation on the EU retail electricity and natural gas market appear
to be on par with what is observed in the market of mobile telephony, these
same levels seem almost insignificant when compared to the variation in labour
costs across the EU: the ratio of highest to lowest average salary in the EU is
more than 3 times larger than what can be observed for electricity or natural
gas prices for final consumers. In that sense, the variation of labour-related costs
may appear as more important driver impacting competitiveness and investment
decisions than energy-related costs; at least for industries that are
relatively less energy intensive.
Another report
from the Commission[8] finds that price dispersion increases when
taxes are included, which confirms the contribution of taxes to the
heterogeneity of energy prices. Interestingly, price dispersion is not observed
on electricity wholesale markets where spot price has progressively converged
over the past years. In well-functioning energy markets, retail prices would be
expected to mirror the process of convergence observed upstream (wholesale). Obviously,
the relative higher dispersion of retail prices has to do with other factors
than wholesale market fragmentation.
Yet, the
dispersion of electricity and gas retail prices for households and industry
within the EU appears about 3 times larger than in the case of retail prices of
motor fuels (gasoline had a variation coefficient of 0.12 in 2008 and 0.10 in
2012, while coefficient for diesel has been stable across the period at 0.09).
The market for motor fuels provides a good benchmark for the gas and
electricity markets: it is a mature energy product market where the taxation
element has a relatively big share of the final price. Still price conditions
are in general quite similar across borders, consumers can choose from several
competitive offers and price levels (which are not regulated) react relatively
quickly to signals from the wholesale market.
Table 1. Dispersion metrics, all taxes included
 Market || Year || Max/Min || Variation coefficient[9] 
 Electricity, households || 2008 2012 || 3.38 3.11 || 0.30 0.28 
 Electricity, industrial consumers || 2008 2012 || 3.15 3.85 || 0.29 0.32 
 Natural gas, households || 2008 2012 || 3.67 4.62 || 0.30 0.29 
 Natural gas, industrial consumers || 2008 2012 || 2.60 3.02 || 0.26 0.26 
 Gasoline || 2008 2012 || 1.58 1.43 || 0.12 0.10 
 Diesel || 2008 2012 || 1.52 1.41 || 0.09 0.09 
 Mobile communications[10] || 2008 2010 ||   || 0.21 0.30 
 Labour market, Industry, consumption, service || 2008 2012s || 14.54 13.42 || 0.54 0.56 
Source:
European Commission (Eurostat, DG ENER, DG ECFIN)
A Commission consumer
market study on the functioning of the vehicle fuels market[11] confirms that major
components of the final consumer prices are due to fuel taxes and VAT rates,
which differ among Member States. Differences in pre-tax prices are much less
than those of post-tax prices, which shows that national tax policies explain
much of the observed differences in prices experienced by consumers. This is true
for both average gasoline and diesel prices. The highest price components are
generally found in EU15 Member States, with absolute highest levels for petrol
seen in the Netherlands, Italy, the UK, Greece and Sweden and for diesel prices
in the UK, Italy, Sweden and Ireland in 2012.

1.1.           
Developments in the retail markets for electricity

Retail
electricity prices expressed in Euros
Looking at the
period between 2008 and 2012, nearly every EU Member State has seen an increase
in household electricity prices. On average, the EU household electricity
prices increased by more than 4% a year between 2008 and 2012[12].
Whilst Romanian electricity prices have actually declined since 2008, others
have experienced average annual increases of 9-10% (Latvia, Spain, Cyprus). 
In the same
period industrial electricity prices (excluding VAT and recoverable taxes)
have gone up by about 3.5% per year. In some countries retail industrial
prices have actually decreased over the period in question (Czech republic,
Denmark, Croatia, Hungary, Ireland, the Netherlands, Romania, Slovenia and
Slovakia), while industrial users in countries such as Estonia, Lithuania and
Latvia have experienced annual growth of more than 8%.
Figure 3.
Evolution of retail prices, electricity, domestic and industrial consumers,
centsEuro / kWh
Retail electricity prices
expressed in purchasing power standards
Taking into
account purchasing power effects does not change the picture above in terms of
price trends but it does change substantially the relative position of
the Member State. The most pronounced increases are those observed in new
Member States. As a group these countries register price increases in terms of
PPS, indicating that the median household and industrial consumers from new
Member States spend a relatively larger portion of their budgets to the
purchase of the same amount of electrical energy. 
Taking into
account the relatively higher levels of energy intensity of new Member States
suggests that those economies might be more vulnerable to price risks related
to the different components of the electricity and natural gas bill. 
Figure 4.
Evolution of retail prices, electricity, domestic and industrial consumers,
cents PPS / kWh
Map 1 Household electricity prices vs. inflation (HICP)
Map 2.
Industrial electricity prices vs. inflation (PPI)
Comparing
electricity price changes to inflation levels
The maps
compare the increase in electricity prices against the increase of the general
price level in each Member State.
As indicated by
Map 1, in 19 out of 28
Member States the median household consumer bands experienced a price increase
in electricity which was higher than the increase in the general price level[13] as measured by the
harmonized index of consumer prices (HICP). Belgium, Denmark, Italy,
Luxembourg, Hungary, the Netherlands, Romania, Sweden and the UK were the
exceptions to that rule.
The combination
of actual changes in electricity and general price levels between 2008 and 2012
was unique for each Member State and the map colours illustrate only the
relative position of those changes. In Estonia, Spain, Cyprus, Latvia,
Lithuania and Portugal electricity prices, inclusive of all taxes, increased by
more than 30% between 2008 and 2012. For the same period, inflation increased
by 10% or more in Bulgaria, Estonia, Greece, Cyprus, Lithuania, Luxembourg,
Hungary, Malta, Poland, Romania, Slovakia, Finland and the UK.
Turning to
industrial consumers and comparing the price rise in electricity (excluding VAT
and other recoverable taxes and levies) and the general industrial price level,
as measured by the Producer Price Index (Map 2), Member States were split by
half. As a rule, electricity price changes were smaller than those for domestic
consumers and in several countries (the Czech Republic, Denmark, Ireland,
Hungary, the Netherlands, Romania, Slovenia, Slovakia and Sweden) electricity
prices actually decreased.
Comparing
electricity price changes to exchange rate variations
During the 2008
– 2012 period, the Romanian, Polish and Hungarian currencies depreciated by
21%, 19% and 15% respectively. Thus, while median retail prices for Romanian
households were registering a modest decrease when measured in Euro cents per
kWh ( -2.45%), those same prices increased by 20% when measured in Lei per kWh.
Similar trends were observed for the other countries with notable currency
depreciation.
Sweden was the
only Member State that witnessed the opposite evolution as the Krona
appreciated by 10% in 4 years relative to the Euro. As a result, whereas
electricity prices for domestic consumers registered moderate increases when
measured in the national currency, more pronounced changes were recorded in
Euros. In the case of median industrial consumers, a decrease in price measured
in Kronor actually translated into an increase when converted into Euros.

1.1.1.      Electricity retail price developments by components

Figure 5 illustrates the aggregate EU numbers weighted by electricity
consumption respectively for households and industrial users.
Figure 5.
Evolution of EU28 electricity retail price by components: levels, selected
household and industrial bands
 || 
   || Source: Eurostat Energy Statistics 
Note: Prices include all taxes in the case of
households. Prices exclude VAT and other recoverable taxes in the case of
industry, as well as industry exemptions (data not available).
Based on
available data from the most recent 5-year period, the European retail prices
(nominal) for electricity increased on average by 3 Euro cents per kWh. Whereas
the energy component remained the most important element in the end consumer
bill, its relative share registered significant decreases (more than 10 % for
industrial consumers and about half as much for households). As the relative
share of network costs remained relatively stable, representing about a third
of the bill, it was the taxation component that filled the gap left by the
supply of energy component. 
The next chart
illustrates these evolutions. Taxes and levies went up by the most, especially
for industry. In the case of the EU weighted average price it increased by
127%. The chart includes only non-recoverable taxes for industry (e.g.
excluding VAT and other recoverable taxes) and exemptions are not reported. For
the large majority of Member States the share of taxes and levies is still
below 10% of ex-VAT prices, even though for Germany, Italy and Austria it
exceeds 20%[14]
In the case of
households, the taxes and levies component of the EU weighted average price
went up by 36.5% and its share accounts on average for 30% of the final price
(up from 26% in 2008).
Network costs
went up by 30% for industrial consumers and by 18.5% for households. While this
increase is smaller than in the case of taxes and levies, network charges
constitute a much more important element of final prices, reaching 50% in the
case of households (CZ) and 56% in the case of industrial consumers (LT).
Figure 6. Evolution of EU28 electricity retail
price by components: percentage change, selected household and industrial bands
Note: Prices include all taxes in the case of
households. Prices exclude VAT and other recoverable taxes in the case of
industry, as well as industry exemptions (data not available).
The energy
element went up only slightly in the case of households and indeed went down in
the case of industrial consumers. 
With these
general findings it is important to point out that part of the increase in the
taxes and levies includes financing for energy supply costs and that
"network" costs can include other charging elements (e.g. for RES or
other financing needs). Member State reporting is inconsistent in this regard
and needs to be improved.
The next two
charts illustrate that the developments observed for the median consumers were
quite representative for the remaining consumer bands as well. As a rule, the
taxation element registered the highest increases across all bands, followed by
increases in the network components of half that magnitude, whereas the costs
related to the supply of energy remained stable.
Figure 7.
Evolution of EU 28 electricity retail price by components, all household
consumer bands
 ||           
The increase in
the non-recoverable taxation element was significantly higher for industrial
consumers. The network and energy elements were stable, even slightly negative
for the larger consumer bands. As the relative share of non-recoverable taxes
currently represents a small portion of the final bill, network costs were
among the most likely price drivers.
Figure 8.
Evolution of EU 28 electricity retail price by components, all industrial
consumer bands
 ||       
Components
at national level
The weighted
average EU numbers conceal a great deal of variety between Member States. The
chart on the next pages illustrates the evolution of the energy, supply,
network and taxation components for each Member State and for the median
household consumer band in 2008 – 2012. 
Figure 9.
2008-2012 evolution of the retail price of electricity, median households by
component
Note: Prices include all taxes.
The percentage change of the level of the
energy component of household electricity prices varied in a
range of -34% in Denmark and +55% in Estonia over the period 2008-2012. During
the same period the network costs of households decreased in the UK (-21%) and
more than doubled in Spain (+152%[15]). The largest growth in taxes and levies on electricity prices for
households was in Portugal, where the component level went up by more than 100%[16] and in Latvia where it increased by almost 400%[17].
Figure 10. Retail electricity prices, Household consumer band DC; 2008 – 2012
percentage change by component
Source:
Eurostat, energy statistics
In 2008 taxes
and levies represented on average 26% of the bill, being as low as 5% for
Malta, the UK and Lithuania and accounting for more than half of the bill in
Denmark (52%). In 2012 the relative share of taxes reached 30% on average,
ranging from 5% in the UK, to close to 30% in Austria, Estonia, Finland,
France, Italy and Sweden and reaching 43%, 46% and 56 % respectively in
Portugal, Germany and Denmark. The share of taxes decreased marginally in
Belgium, Bulgaria, Malta in Poland while it grew by more than 10% in Latvia and
Portugal.
Figure 11.
Relative share of components, households
Source:
Eurostat, energy statistics
Note: Prices include all taxes
A further look
into the different elements of the electricity bill of residential consumers is
provided by the Household Energy Price Index (HEPI) from E-Control and VaasaETT[18]. Each month since
January 2009, it has been reporting electricity prices paid by residential
consumers in 15 capitals of the EU since 2009. It also provides an alternative
breakdown of the taxation component into taxes related to energy policies and
VAT and other recoverable taxation instruments.
Figure 12. EU15:
electricity retail prices – residential consumers in capitals, 2009 – 2012
evolution
Figure 13. EU15:
electricity retail prices – residential consumers in capitals; 2009-2012
differences and percentage changes by component
Figure 14. 2008-2012 evolution of the retail price
of electricity, industrial consumers by component
Note: Prices exclude VAT and other recoverable taxes
in the case of industry, as well as industry exemptions (data not available).
In the case of
industrial electricity prices[19],
between 2008 and 2012 the energy component went up by more than 30% in
Lithuania, while it went down by 40% in Denmark. Network costs doubled in
Latvia and Italy, but went down by 17% in Romania. Taxation increased many-fold
in the following countries: Germany (RES levy and electricity tax), Estonia
(RES tax and electricity excise tax), Finland (electricity excise tax), Hungary
(increase in support for district heating, partly compensated by decreases in
support for retirement schemes for electric industry employees and support for
coal industry restructuring), Italy, Slovenia (contribution to provide security
of supply by using domestic primary energy sources for electricity production,
contribution to support the production of electricity in high efficiency
cogeneration and from renewable resources, addition to fuel prices for the
improvement of energy efficiency and an increase in excise tax) and Slovakia
(increase of the excise tax and introduction of other taxes linked to the
energy sector)[20].
The taxation component remains still a fairly minor part of industrial prices
in most of these countries, except for Germany and Italy. More Member State
specific information is available in Error! Reference source not found..
Figure 15. Retail electricity prices, Industrial consumer band IC; 2008 – 2012
percentage change by component
Source:
Eurostat, energy statistics
Note: Prices exclude VAT and other recoverable taxes
in the case of industry, as well as industry exemptions (data not available).
In 2008 taxes
and levies represented on average 9% of the bill, being as low as 0.5% for
Slovak consumers and reaching 16% in Italy. In 2012 taxes were counting still
for less than 2% in Bulgaria, the Czech republic, Croatia, Lithuania and Sweden
while they reached 32 in Germany; the average EU level reached 18%, well above
the maximum level registered in 2008.
Figure 16. Relative share of components, industrial consumers
Source:
Eurostat, energy statistics
Note: Prices exclude VAT and other recoverable taxes
in the case of industry, as well as industry exemptions (data not available).

1.1.1.1.                  
Costs related to energy and supply

In the case of electricity
prices paid by households, in 2012 the energy component was between 3.2
Eurocent/kWh (Romania) and 20.4 Eurocent/kWh (Cyprus) and accounted for between
18% (Denmark) and 82% (Malta) of the household electricity price (see Figure 14 on p. 23). Median industrial consumers paid
between 3.4 Eurocent/kWh (Estonia) and 20.1 Eurocent/kWh (Cyprus) for the
energy component in 2012, its share in the final bill[21] ranging between 39% (Denmark)
and 88% (Malta).
The wholesale
market developments have influenced the energy – related component of
the end consumer bill. As an asset class, energy commodities followed the
market turmoil triggered by the financial crisis and the recession fears in
most of the world’s leading economies throughout the second half of 2008.
Prices for crude oil, coal, natural gas and electricity experienced similar
price corrections, as illustrated by Figure 17. Since then European electricity
prices evolved within a range of EUR 40 / MWh – EUR 60 / MWh, representing
60%-70% of the price levels of January 2008. Fossil fuel prices were more
volatile.
Figure 17. Evolution of European average wholesale electricity
prices vis-à-vis coal and gas prices 
Notes: Platts PEP: Pan European Power Index (in
€/MWh), Coal CIF ARA: Principal coal import price benchmark in North Western
Europe (in €/Mt), Natural gas NBP: price for natural gas delivered at the
national balancing point, a virtual trading location for sale and purchases of
gas at the UK gas grid 
The EU’s main
electricity markets have followed a similar trend, reflecting seasonal and
regional specificities of the different price areas, as indicated in Figure 18 which illustrates the price
evolution for the leading day-ahead indices[22].
In spite of some significant increases experienced over the period examined,
subsequent decreases have resulted in wholesale electricity prices by the end
of the period (June 2013) reaching levels close to those at the beginning of
2007 and well below peaks in 2008. 
During the
observed period (H2 2008 – H2 2012) the prices of the major European
wholesale electricity benchmarks decreased by 35 – 45 % as markets remained
well supplied. This is in clear contrast to the trend in retail prices. 
Figure 18. Selected European
benchmarks, wholesale electricity prices
 Source: Platts 
Prospex
Research[23] estimates that the total electricity trading volumes in the mature
EU markets, including exchanges and over-the-counter trades (OTC), stood at 8
500 TWh in 2012. This compares to a gross inland consumption for electricity in
EU27 in the range of 3 000 – 3 200 TWh. The traded volumes recorded a second
consecutive year of decrease, mostly linked to a reduction of trading activity
of a number of banks and major utilities such as EDF, E.ON and RWE.
The German and
Nordic markets remained the European leaders by a wide margin in terms of both
total trading volumes and market development. The churn factors[24] of these markets have
been estimated respectively at 7.1 and 5.
With regards of
market sectors, OTC remained the favoured choice of trading, representing about
2/3 of total volumes. Yet, compared to previous years, OTC volumes declined
significantly. The larger part of OTC is non-cleared on exchanges.
Despite the
difficult conditions, the exchange spot trading remained the only segment to
register steady increases of volumes. About 1 200 TWh were exchanged in 2012, reaching
14%, which is an increase compared to the year before. Among the factors
shaping the evolution described above were the recession and slow economic
recovery thereafter that affected energy demand, especially from industry,
coupled with new electricity generation assets coming on-stream. 
The frequency
of occurrence of negative price episodes[25]
rose in the last part of the observed period as the costs of ramping up or down
of some conventional plants are significant.
Some of the new
generation plants (wind, solar) impacted directly the supply curve[26] of the day-ahead
market as their low marginal generation costs allowed them to outbid
conventional electricity generators. As such, the RES units contributed to
keeping the wholesale price in check through the merit order effect, as explained
in Error! Reference source not found.. In a normally functioning energy market, the decreased wholesale prices
should pass through to final consumers in the form of lower cost of the
energy supply component.
Figure 19
Evolution of share price indices: European Utilities vs. European Blue Chips
At the same
time, policy support measures (including renewables and energy efficiency
support and other energy subsidies) increase the levy element of retail prices or the transmission charges, while the costs of
network development and ancillary services increased
the network element. Thus overall, retail prices rose. 
The combination
of weak demand, stable wholesale electricity prices (when hydrocarbon prices
were on the rise) has put pressure on conventional assets (at times resulting
in companies adopting faster depreciation rates). In many cases both the profit
margins from the generation business and company share prices were negatively
affected, (as can be seen from the evolution of the Euro Stoxx Utilities index
on Figure 19), and access to
finance has been more difficult. 
Figure 20 Reported Net Income for the Bloomberg EU Power Generation Top Index in € millions (2002-2012)
Source: Bloomberg
Reported net income for European electricity
generation utilities demonstrates this negative trend in profits, as
illustrated in Figure 20.
Whereas fortunes had been rising throughout the first decade of the millennium,
profits rapidly declined after a peak in 2009 before reaching a plateau in
2011. Earnings have not, however, stabilized across Europe, as European
utilities are not equally exposed to the new risks facing the industry. Firms
with large shares of coal generation have a different short-term outlook than
those with large shares of gas generation due to low ETS credit prices and
cheap coal prices resulting from increased American exports. Moreover, Central
European utilities (E.ON, GDF Suez, RWE, PGE and CEZ) have been particularly
hit due to their exposure to electricity prices. However, electricity generation
utilities have fared poorly in other regions as well (Endesa, PGE).
As a rule, the
EU utilities have tried to adapt to this new business environment by focusing
more on downstream services, including decentralized generation and energy
efficiency and by gradually divesting their conventional electricity generation
assets.
In an open and
competitive retail market the energy component of the end consumer price (Figure 1) for electricity would reflect
generation costs, as represented by an efficiently functioning wholesale market[27] and the quality of
services provided by the energy supplier; the network component would reflect
the costs of the efficient operation and balancing of the transmission and
distribution grids, including the demand side response, and the taxation
component would be set in such a way, so as to achieve taxation and energy
policy objectives with the least burden on consumers. 
In addition,
pricing signals should provide a strong link between the retail and wholesale
segments, ensuring a completeness and coherence of the market structure. A
strong and relatively quick pass-through of any persistent, long term
change of the wholesale benchmark to the energy component in the retail price
would indicate a good / normal operation of the IEM. The final consumers would
then be able to adapt their economic decisions in line with the supply and
demand fundamentals.
These
conditions are rarely met in today’s retail markets in the EU. The normal
operation of the market is often restrained by a variety of factors and
barriers that limit competition. Measuring barriers to entry is difficult in
the case of electricity and natural gas markets, not least because harmonised
methodologies to support data collection of relevant retail market indicators
are still missing. 
Elements that
may slow down the interaction between retail and wholesale sections include but
are not limited to: consumers' low ability and propensity to switch behaviour, sticky
retail prices and non-market based price regulation. 
In a
competitive retail market the empowered and price-sensitive energy consumers
have a wide range of options when it comes to finding attractive price offers.
Switching across offers of the current supplier, or switching the supplier, is
just one of those options, yet to be fully used in the case of EU retail electricity
and natural gas markets. 
Understanding consumer
behaviour is in general a complex exercise which is further compounded for the
case of electricity and natural gas. As a rule, the price elasticity of these
commodities is low, implying that end consumers have to be incentivised by a
significant price variation to consider changing behaviour. This may explain in
part why switching rates tend to be low.
Figure 21, coming from the latest
market monitoring report from ACER and CEER (2012)[28], illustrates this for
the case of electricity: it shows that the expected profits from switching
(coming in the form of savings on the bill) have to be substantial to
incentivise consumer switching. In some cases the prospect of saving more than
10 Euros per month, just by switching to an existing offer in the market, may
not be enough to prompt actions from consumers.
Figure 21. Average monthly saving potential
(household consumers, 4000 kWh of annual consumption) from switching from the
incumbent standard offer to the lowest priced offer in the market – capital
city – December 2012 (euro/month)
Non-market
related justifications – such as loyalty to a supplier or a perception of
protection by staying under the administered offer – may not be enough to
explain such behaviour. The complexity of supply offers, the lack of
transparency and user-friendly tools for comparing offers, even ignorance or
lack of interest may be at play as well.
Commission's 2010
in-depth market study on retail electricity market found that current market
conditions (limited transparency and comparability of tariffs and offers,
limited access to information as well as complicated switching procedures) make
it very difficult for EU consumers to compare the different offers and choose
the best deal, or to subsequently switch providers. The study estimated that
62% of consumers could switch to a cheaper tariff, representing a potential
average annual saving of EUR 13 billion EU-wide.[29]
For a large
group of consumers, the retail prices also tend to be sticky: such
consumers would sign contracts where prices and consumed amounts are set
ex-ante and where metering and ex-post bill settlement takes place on regular
intervals (matching real and estimated prices and consumed volumes).
Demand-side participation on the wholesale market is thus discouraged and so is
the transmission of pricing signals between the retail and wholesale segments. 
As indicated by
the ACER-CEER report, Member States continue to administer retail prices for
electricity over vast portions of household and industrial consumers: “in
2008, 130 million out of 229 million of household consumers in Europe were
supplied under regulated prices, i.e. 57%. This share decreased only to 51%
four years later. Whilst in several MSs regulated and non-regulated
prices co-exist, the tendency for household consumers to switch from regulated
to non-regulated prices is rather low”.
It should be
noted that several Member States have committed themselves to timetables to
phase out retail price regulation and other Member States are considering such
a phase out. In a few other Member States, isolated wholesale markets would not
for the time being allowing competition to keep prices at check in the retail
markets. Retail price regulation might in these instances not have a major
distortive impact.
Non-market
based regulated prices tends to distort the normal
operation of retail markets; service quality and innovation tends to be lower
than it would otherwise be. Moreover, the implementation of smart demand
response solutions, which allows consumers to take advantage of fluctuating
just-in-time prices, and which depend on flexible pricing formulas, risks being
hampered by retail price regulation.
Moreover, in
these cases incentives for energy efficiency are greatly reduced and an
additional financial burden is placed on consumers in their capacity of
taxpayers in order to finance the non-covered costs
A recent
European Commission service report found out that price
regulation also leads to cross-subsidisation among consumer groups[30]. When prices are set below costs, tariff deficits may accumulate in
the balance sheet of companies that are present on the market. Profit margins
of companies deteriorate and the related uncertainty might have a negative
impact on the cost of capital, which impacts in turn investment decisions.
Switching behaviour would be further discouraged as consumers would not see any
need to look for competitive offers and new entrants would stay away from the
market.
A regulation
setting prices above costs can also distort retail markets and act as a
deterrent to new entry. It clusters offers around the regulated level and
discourages switching; it also creates unnecessary burden for National
Regulating Agencies as the definition of the regulation methodology may become
a contested topic in the political debate and thus subject to frequent
modifications.
Map 3 Method of price regulation (electricity)
and update frequency in months in Europe - 2012
Whereas the
drive to regulate prices may be prompted by legitimate concerns as the
protection of certain vulnerable consumer groups, regional policies, secure
supplies, etc. these concerns can be better addressed through policies which
are less distortive on the retail markets, in particular focussed financial
support of vulnerable consumers that enable these customers to source energy at
competitive market prices. 
Map 3, again from the ACER-CEER report,
illustrates that 18 Member States continued to regulate prices in 2012. Price
regulation methods for the energy component of the retail price for electricity
are specific for each Member State. As mentioned, “11 out of 18 Member
States with regulated electricity prices apply rate of return/ cost plus
regulation (i.e. Cyprus, France, Greece, Hungary, Italy, Latvia, Malta,
Northern Ireland, Poland, Romania and Spain). Price cap is applied in five out
of 18 MSs (i.e. Denmark, Estonia, Lithuania, Portugal and Slovakia). Bulgaria
regulates end-user prices by applying the revenue cap regulation for end
suppliers and distribution companies”.
The factors slowing down the completion of
the retail segment of the internal market are also contributing to the
generally negative perception of consumers with regards to the quality of the
service provided. As consistently shown by the Commission's Consumer Markets
Scoreboards[31], the electricity and natural gas sectors are rather poorly assessed
by consumers. In 2013, the electricity market ranked 28th out of 31
services markets, with market performance significantly differing from one
country to another and particularly low scores in Southern European countries[32]. The market has particularly poor scores on the choice of suppliers
available in the market, comparability of offers and trust in suppliers to
respect consumer protection rules (2nd, 4th and 5th
lowest among all services markets, respectively). In addition, only 4% of
consumers have switched products or services with their existing provider and
7% switched supplier during the past 12 months (4th lowest among the
14 'switching services' markets) and the switching process is perceived as
relatively difficult. All this suggests that consumers do not yet have the
conditions to make full use of the saving opportunities created by market
liberalisation[33]. 
According to Commission services' empirical
estimate on electricity price drivers[34], market opening plays a downward effect on end user prices. Policies,
such as unbundling of the electricity activities benefited end users by
lowering the retail prices through higher competition among suppliers and more
efficient monitoring of network costs.  At the same time, fossil fuels are
still important drivers and countries that have access to low marginal cost
plants, such as nuclear and coal plants, face lower wholesale prices compare to
countries that depend on high marginal cost, such as open cycle natural gas and
oil plants. Finally, the RES penetration at times contributes to increasing the
retail prices through the levy's component, as the cost of the supporting
schemes may outweigh the benefit of lower wholesale prices resulted by renewables
(see Error! Reference source not found.). However in many countries, the cost of RES supporting schemes is increased
unevenly among consumer groups (particularly households) due to the
government's protection of energy intensive industries. Industries.
As some industries are exempt from RES-related
levies, the majority of the costs brought about by investments are to be borne
by household consumers in some Member States (e.g. Germany). However in other
Member States the situation appears to be different and lessons are to be
learned from different national experiences

1.1.1.2.                  
Costs related to networks

In 2012 median
households paid in the range of 2.2 Eurocent/kWh (Malta) to
9.6 Eurocent/kWh (Spain) for the network component and its share
represented between 13% (Cyprus and Malta) and 50% (Czech Republic) of the
total bill. For industry, network costs represented between 11% (Cyprus) and
56% (Lithuania) of the end price and consumers paid between 1.66 Eurocent/kWh
(GR) and 6.46 Eurocent/kWh (Lithuania).
The proceeds collected from the network
component of the end consumer bill are intended to cover capacity and operating
expenses related to the transmission and distribution grids. Both businesses
are run as regulated activities and the expenses can be schematically broken
down into infrastructure costs (maintenance and grid expansion), system
services (costs by use or by availability), network losses and other charges
such as (but not limited to) stranded costs, public service obligations, policy
support to certain technologies, etc.
Direct
comparison of unit tariffs should be done with caution due to differences
between countries in areas such as quality of service, market arrangements,
main technical characteristics, topological and environmental aspects of the
networks, e.g. consumption density, generation location, that influence the
level of such charges. On the transmission side these relate to costs of
infrastructure, energy losses, ancillary services, system balancing and
re-dispatching.
Figure 22 presents a breakdown of the
network costs into transmission and distribution components starting from the
total network values reported by Eurostat. These values
are only indicative as they may include elements which are not directly related
to the operation of the transmission and distribution grid. Such is the case
for a number of Member States estimated to be on the high end of network costs.
More elements are needed to conduct a thorough analysis on the drivers
affecting network costs. What emerges is that, barring few exceptions,
distribution costs are by far the larger part of this component.
The split of
electricity transmission and distribution costs within network costs
also varies significantly across Member States – Spain, Denmark, Lithuania,
Latvia and Slovakia have rather high distribution costs. Transmission costs are
relatively high in Slovakia, Ireland, the Czech Republic, Croatia, Lithuania
and Spain.
Detailed and
harmonized information on the distribution grids of the EU is in general
scarce. For the majority of the distribution grids, not much is known even on
basic data such as total length and age of operation by component[35]. It is also not clear if national regulators are applying similar
accounting rules and methodologies to determine the level of the distribution
and, to a lesser extent, the transmission tariff.
The observed
differences in network charges may result not only from differing underlying
transmission and distribution costs, but also from different regulatory cost
assessment methodologies in use by NRAs at TSO and/or DSO level (asset
eligibility, asset valuation and asset remuneration for instance). Figure 23 provides data on some basic
elements of the transmission grid.
Figure 22. Breakdown of network costs into transmission and distribution (levels + shares)
Note: certain Member States add non network
costs to network charges, which are not distinguished in the data. For example,
Spanish data reported to Eurostat includes capacity payment (pagos por
capacidad) and premium payments for RES and CHP (Prima Régimen especial)
under network costs. Similarly, Danish data reported to Eurostat classifies
Public Service Obligations under network costs.  
The total network costs are calculated as a
weighted average of network costs for household and industrial consumers (consumer
bands DC and IC), as reported by Eurostat. Transmission costs are those
reported by ENTSO-E. Distribution costs are estimated as the difference of total
network and transmission costs. Data limitations do not allow splitting network
costs in Luxembourg, Cyprus and Malta. 
ENTSO-E calculates the unit transmission
tariff taking into account the whole of the tariff: adding the invoices applied
to the load and to the generation (if applicable), and assuming they produce
and consume the energy they had in their programs (without individual
deviations). ENTSO-E makes the following assumptions: 5000 h utilization time
that includes day hours of working days, typical load considered is eligible
and has a maximum power demand of 40 MW when it is connected at EHV and a
maximum power demand of 10 MW when it is connected at HV, for countries with
tariff rates that are differentiated by location an average value has been
taken. 
Figure 23 Length and relative share of Member
States electricity transmission grids by voltage level
   || < 110 kV (km) || 110-330 kV (km) || > 330 kV (km) || Total (km) 
 AUSTRIA || 1808 || 9199 || 3929 || 14936 
 BELGIUM || 1447 || 4483 || 4781 || 10712 
 BULGARIA || 3323 || 2828 || 8274 || 14425 
 CROATIA || 982 || 5943 || 2446 || 9371 
 CYPRUS || 0 || 968 || 328 || 1297 
 CZECH REPUBLIC || 3950 || 2206 || 5369 || 11525 
 DENMARK || 2514 || 3761 || 3149 || 9424 
 ESTONIA || 2118 || 4131 || 1077 || 7325 
 FINLAND || 4282 || 10061 || 9193 || 23536 
 FRANCE || 21562 || 28605 || 51186 || 101353 
 GERMANY || 20057 || 34824 || 30354 || 85234 
 GREECE || 4353 || 12223 || 1010 || 17586 
 HUNGARY || 2612 || 15535 || 1419 || 19566 
 IRELAND || 435 || 6485 || 3 || 6923 
 ITALY || 11986 || 19103 || 23581 || 54670 
 LATVIA || 1378 || 3929 || 310 || 5617 
 LITHUANIA || 1544 || 4186 || 2050 || 7779 
 LUXEMBOURG || 0 || 167 || 538 || 704 
 MALTA || 0 || 34 || 190 || 225 
 NETHERLANDS || 3289 || 6958 || 133 || 10380 
 POLAND || 6348 || 7625 || 9835 || 23808 
 PORTUGAL || 1813 || 5592 || 67 || 7472 
 ROMANIA || 4474 || 4444 || 9334 || 18252 
 SLOVAKIA || 1647 || 978 || 4776 || 7401 
 SLOVENIA || 396 || 2410 || 1 || 2807 
 SPAIN || 16911 || 37901 || 7896 || 62709 
 SWEDEN || 11852 || 5638 || 24625 || 42116 
 UNITED KINGDOM || 12459 || 33995 || 3535 || 49989 
   ||   ||   ||   ||   
The work of TSOs within ENTSO-E may prove
to be a good example to follow in bringing transparency on the operation of
distribution networks. As more and more generation assets are connected to the
low voltage level the need to reinforce the grid at that level increases. Grid
expansion financed only by public investments may be difficult. So ensuring
adequate financial framework to attract potential investors, may be necessary.
The next chart presents the components of
the transmission tariffs, as represented by the latest ENTSO-E overview[36].
Infrastructure costs are in the 0.2 – 1
Eurocent / kWh range; system services including balancing are more variable
with the ratio between the lowest to highest per Member State exceeding 1 to
10. Losses are globally comparable. The other regulatory charges are not
directly related to TSO activities and include elements such as: stranded
costs, public interest contribution, renewable energy and other. A detailed
description by country is provided in Annex 5 of the above-mentioned
publication.
Figure 24.
Components of transmission tariffs, EUR/MWh
 Source: ENTSO-E Overview of transmission tariffs in Europe: Synthesis 2013 

1.1.1.3.                  
Costs related to taxation

In 2012 median
EU households paid between 0.85 Eurocent/kWh (UK) and 16.8 Eurocent/kWh (Denmark)
for the taxation component which accounted for between 5% (UK, Malta) and 56%
(Denmark) of the total bill.
The share of
the taxation component (net of VAT and other recoverable taxes and levies) for
industrial consumers varied in the range of 0% (Romania, Lithuania, Latvia, Malta)
to 32% (Germany) of industrial electricity prices (excluding recoverable taxes)
with levels of up to 5.5 Eurocent/kWh (Italy). 
In general,
taxes on energy can be divided into broad consumption taxes (such as Value
Added Tax, VAT) and specific taxes (such as excise duties, energy and carbon
taxes). VAT is a general tax that applies, in principle, to all commercial
activities involving the production and distribution of goods and the provision
of services. VAT is a consumption tax borne ultimately by the final consumer as
a percentage of price. In contrast, excise duties are indirect and specific
taxes on the consumption or the use of certain products, which are expressed as
a monetary amount per quantity of the product.
Where carbon
taxes are in place, they are generally designed to complement rather than
overlap with the ETS, and ensure a similar burden share between ETS and non-ETS
sectors. This is the case in Denmark and Sweden, for example. The UK has in
place a Carbon Price Floor, which acts to "top up" the price of
carbon allowances in the ETS.
The overall
effect of high energy taxation depends on the use of tax revenues. The IEA
points out that while taxes on the sale of energy to industry can affect the
sector's international competitiveness, this effect can be offset – to some
degree – by government interventions designed to improve industrial
competitiveness, such as government measures and programmes aimed at
improvements to infrastructure, support for investments. 
Tax Rates -
VAT and excise duties
The VAT
Directive[37]
provides a legal framework for the application of VAT rates, establishing a standard
rate of at least 15% and allowing for Member States to apply one or two reduced
rates of not less than 5% to goods and services enumerated in a restricted list.
In the case of electricity, VAT rates do not differ considerably across Member
States. Since 2009, many MSs have raised VAT rates, in general affecting both
commercial and non-commercial consumers. Standard VAT levels vary between 15%
and 27% across Member States, with a range of 19-21% most commonly observed. 
Some Member
States apply reduced VAT rates on electricity consumption: for example, the
United Kingdom charges a reduced VAT rate of 5% on electricity in the case of
households, while Luxembourg, Ireland and Greece charge reduced VAT rates of 6%,
13.5% and 13%, respectively, on electricity consumption for both business and
non-business use. VAT rate on electricity in Croatia, Sweden and Denmark is at
25% and in Hungary at 27%. 
Reduced
VAT-rates on energy products may reduce the incentives for energy efficiency
efforts for household consumers.
Figure 25. VAT rates on electricity
Source:
European Commission 
Note: *Reduced
VAT rate of 5% for electricity non-business use in the UK. 
**Reduced VAT
rates for electricity (business and non-business users) in Ireland, Greece and
Luxembourg.
 
In the EU the
general framework for energy taxation is set by the Energy Tax Directive, which
set minimum levels of excise duty for a wide range of energy sources and
fuels, plus electricity, while recognising that "certain exemptions or
reductions … may prove necessary … because of the risks of a loss of
international competitiveness or because of social or environmental
considerations". According to the Energy Tax Directive the minimum
levels of excise duty for electricity amount to 0.5 Euro/MWh and 1 Euro/MWh for
business and non-business use respectively. 
The levels of
excise duty which Member States charge in addition to the minimum rates set by
the Directive vary significantly by country. About half of the Member States
enforce rates either at or slightly above the minimum (typically up to 1.5 Euro/MWh).
On the other hand, significantly higher rates of taxation are found in Northern
European and Nordic Member States. In the case of non-business use, Germany
imposes a tax rate of up to 20 Euro/MWh, Sweden of up to 34 Euro/MWh and
Denmark of over 109 Euro/MWh[38].
Excise duties
are frequently applied unevenly across sectors; many Member States set lower
rates for commercial, industrial or domestic use. Member States enforcing lower
rates of excise duty for electricity use by business sectors (in comparison
with non-business use) include Denmark, Germany, Greece, Finland, Italy,
Lithuania, Romania and Sweden.  The scale of the disparity between sectors
varies by country: in Germany, business versus non-business rates stand at
15.37 Euro/MWh to 20.57 Euro/MWh; for Finland, this was
7.03 Euro/MWh to 17.03 Euro/MWh; for Romania 0.5-1 Euro/MWh and for
Lithuania 0.52 to 1.01 Euro/MWh.
Countries that
impose lower effective tax rates on industrial use may be seeking to address competiveness
concerns, particularly in relation to energy-intensive industries that are
subject to strong international competition. On the other hand, in EU
countries, the lower rates may to some extent reflect the fact that many large
industrial emitters are subject to the EU emission trading system. Countries
that impose lower rates on residential fuel use may place greater weight on
affordability and vulnerability concerns.
The precise
distribution of exemptions from excise duties also varies by Member State. In
Sweden this applies to manufacturing industry as well as agriculture,
horticulture, fisheries and forestry. In Finland, the reduced rates apply to
industry and greenhouse cultivation. In Greece, the exemptions apply to
consumers of high voltage electricity, while other business use is taxed at the
normal rate.
In Slovakia,
Greece and Bulgaria, domestic electricity consumption is exempt from excise
duty. In the UK, the Climate Change Levy, the main tax on electricity and
energy use, is paid only on business and public sector consumption. 
Table 2. Excise duties levied on electricity, 2013
 Electricity, EUR/MWh || Non-business use || Business use 
 Belgium (1) || 1,91 || 0 
 Bulgaria || 1,00 || 1,00 
 Croatia || 1,01 || 0,51 
 Czech Republic || 1,14 || 1,138 
 Denmark (2) || 109,99 || 54,42 
 Germany || 20,50 || 15,37 
 Estonia || 4,47 || 4,47 
 Greece || 2,20 || 2,5 
 Spain || 1,00 || 0,50 
 France || 1,5 || 0,5 
 Ireland || 1,00 || 0,50 
 Italy || 22,70 || 12,50 
 Cyprus || 0 || 0 
 Latvia || 1,00 || 1,00 
 Lithuania || 1,01 || 0,52 
 Luxembourg || 1,00 || 0,50 
 Hungary || 1,00 || 1,00 
 Malta || 1,5 || 1,5 
 Netherlands (3) || 114 || 114 
 Austria || 15 ,00 || 15 ,00 
 Poland || 4,56 || 4,56 
 Portugal || 1,00 || 1,00 
 Romania || 1 || 0,5 
 Slovenia || 3,05 || 3,05 
 Slovakia (4) ||   || 1,32 
 Finland || 17,03 || 7,03 
 Sweden || 31,66 || 0,55 
 UK || 0 || 0 
Source: European Commission Excise Duty Tables. 
Notes : (1) In
Belgium, a federal contribution of EUR 2.98 / MWh is collected; there are
number of reductions and exemptions for energy intensive business; (2) Includes
CO2 tax ; (3) Depending on consumption level, the exemptions range
from EUR 0.5 / MWh to EUR 116.5 / MWh; (4) Non-business use is exempted; 
Other
levies
Other
government policies may also be financed through additional energy or
carbon-related taxes, as well as through levies and charges on energy bills,
the composition of which is very different between Member States. Emissions
trading schemes, renewable energy policies, energy efficiency policies and
investment in infrastructure may all have an impact on electricity bills; in
some Member States financing related to these policy priorities is done though
taxes or levies, whereas in others they are instead considered as a factor in
the production cost of energy or in network costs. 
Costs related
to the EU ETS are incorporated in the energy component of prices and current state
of knowledge is that the impact on electricity prices has been relatively
modest, if any. A recent study by DG ECFIN covering data until 2011 did not find any significant impact of ETS carbon prices
on electricity retail prices neither for industry, nor for households. 
In the period
2009-2012 the share of levies and charges used to support electricity generated
from renewable energy sources has increased, rather abruptly in some Member
States. 
In 5 Member
States support for renewable electricity generation in 2012 accounts for more
than 10% of household electricity price, excluding VAT. The steep increase in
the level and the relative share of renewable electricity charges paid by
households in some Member States cannot be disconnected from the fact that
large industrial consumers are often exempt from paying these (see discussion
below). 
Figure 26. Evolution of the share of RES-E levies in the electricity price
for households in selected EU countries (2009-2012)
Note: Only states
with data for all the years in the period 2009-2012 included. Calculated as
% of price for consumers with annual consumption between 2500 and 5000 kWh
(Eurostat consumption band DC), excluding VAT. 
Source:
Commission services calculations based on Eurostat and Member State data
Between 2009
and 2012 industrial consumers in Germany, the Czech Republic, Estonia, Latvia,
France and Romania saw a steep increase in the share of RES-E-related levies in
final price of electricity (excluding VAT and other recoverable taxes), though
from a very low starting level in the cases of the Czech Republic, Latvia,
France and Romania.
Figure 27. Evolution of the share of RES-E levies in the electricity price
for industrial consumers in selected EU countries (2009-2012)
Note: Only
states with data for all the years in the period 2009-2012 included. Calculated
as % of price for consumers with annual consumption between 500 and 2000
MWh (Eurostat consumption band IC), excluding VAT and other recoverable taxes. 
Source:
Commission services calculations based on Eurostat and Member State data
Tax exemptions
The effect of
energy taxes upon different industrial sectors is however complicated by
reimbursements and exemptions which may be available in some countries to
specific sectors. This section provides examples of exemptions provided to
certain categories of consumers in some EU countries that generally tend to tax
energy consumption more heavily. It is beyond the scope of this review to
provide a comprehensive legal and economic analysis of all exemptions and
preferential tax treatments in the EU: comprehensive data on re-imbursements
and exemptions across all Member States are scarce, meaning it is difficult to
build a systematic picture of these exemptions across the EU. It is
nevertheless possible to point to specific examples. 
A 2011 study
carried out by ICF International for the UK government looked at the impact of
energy and climate change policies on energy intensive industries[39] in a select group of
EU countries[40].
This concluded that in the EU Member States examined "energy taxes for energy
intensive industries… are generally low due to significant re-imbursements that
are possible … re-imbursements to EIIs appear most significant for Germany,
Denmark and Italy, and are also relatively high for France". 
In Germany,
certain energy intensive sectors pay a rate on electricity consumption below
the rates for businesses.  Similarly for natural gas, heating use by businesses
is taxed at a lower rate than by non-businesses (EUR 1.14 per gigajoule
compared with EUR 1.53 per gigajoule) and a refund is applied to natural gas
used in industry and agriculture[41].
Under the electricity tax law of 1999 (amended in 2011), the majority of EII
sectors[42]
qualify for a complete reimbursement of energy taxes. 
In addition to
these discounts, German renewables law protects EIIs from the added costs of
electricity owing to preferential grid access for renewables. These costs are
distributed among all electric consumers as an additional levy, with the
exceptions of EIIs meeting certain conditions with regards to electro-intensity[43]. The case studies in
section 1.1.2 confirm that the plants in the German sample paid about 5% of the
full RES-levy size (see Table 5). 
In the United
Kingdom, the Climate Change Levy is a tax imposed on consumption by
business and the public sector of electricity, natural gas and other fuel
sources. Energy intensive industries[44]
qualify for a reduction of 80% on this levy, on condition of meeting certain
energy-saving targets set out in a Climate Change Agreement. Under this scheme,
an energy intensive industrial user would pay GBP 1.018 per MWh, as opposed to
GBP 5.09 per MWh paid by a regular industrial consumer.
In Denmark,
under the Green Tax Package scheme, EIIs are completely exempt from energy
taxes, and almost completely exempt from carbon taxes.[45] Processes which
participate in Voluntary Agreements, committing them to energy efficiency
improvements, are eligible for a rebate of 100% on their energy tax and 97% on
their carbon tax.
In France,
electricity consumed by large industrial consumers is taxed at a reduced rate
slightly below that faced by residential users.[46] The tax rate applied
to industrial users depends on the user's scale and is lower for larger
consumers. The tax rate applied to residential and commercial users is set at
an intermediate level between the rates of for the two types of industrial
users. 
In the Netherlands,
taxes on natural gas and electricity consumption are based on a bracket system,
which sets marginal rates based on the amount of use. The rates decrease with
increased use, and different rate schedules apply for industrial, residential
and agricultural use. Business use of electricity greater than 10 million KWh
pa is exempted if the consumer has agreed to obligations for improving energy
efficiency.[47]
The average tax rates on electricity consumption for industry (calculated by
the OECD) are below those for other sectors (e.g., for electricity, 0.006
Euro/kWh versus 0.113 Euro/kWh for residential use).
In Belgium,
EIIs with an environmental agreement are entitled to a 100% exemption on the
excise tax on fuels they use, as well as on electricity consumption.[48]

1.1.2.      Electricity price developments in selected industries 

This section looks into retail
electricity price developments for several energy intensive industries, based
on samples compiled from a study analysing data at company and plant level[49]. Based on
the methodology described in Error! Reference source not found., the
results of several case studies for selected energy-intensive industries are
presented below with regard to electricity prices. The results are not
representative of either the entire industrial branches in each Member State or
region, or of the EU as a whole. 
The purpose of the case studies is to
complement the statistical analysis with data from real installations, while
acknowledging the limits in terms of interpretation and generalisation of the
results and conclusions beyond the sampled plants. Error! Reference source not found.
provides details on coverage and selection criteria; details on sampling for
each industrial sector are provided in the text.  
Cross-sectoral analysis
Before introducing the detailed results of
the case studies, this section presents and compares the variation of data for
each of the seven sectors assessed.
In particular, for each sector and the
related EU-wide sample (no split into regions) the average electricity prices
paid by the surveyed plants and the standard deviation of price are presented. The applicable consumption ranges are presented using the
median and box plots[50].
The number of
questionnaires used for each sector and each of the two energy inputs is
reported below. The questionnaires that form the basis of this cross-sectoral section
come from a total of 21 Member States. The coverage differs by sector. The
results may not be necessarily representative of the situation of the
respective industrial branches in each Member State or region.
Table 3 Number of questionnaires used in cross-sectoral analysis
 (sub)sector || N. of questionnaires Electricity 
 Bricks and roof tiles || 16 
 Wall and floor tiles || 20 
 Float glass || 10 
 Ammonia || 10 
 Chlorine || 9 
 Steel || 15 
 Aluminium || 9 
 Total || 89 
Note: Based on the number and type of
respondents in each sector as well as the respective Member State of origin,
the criteria used in the sample definition (see Annex 2) have different weights.
This implied that, for some sectors, not all questionnaires received could be
fully used.
As shown in the following graphs, for the
installations sampled, the electricity consumption level increases when moving
from the sector of bricks to the sector of aluminium while increasing
consumption levels are associated to decreasing electricity prices.
The median electricity
consumption in the aluminium sector, as seen from the 9 installations sampled, is
indeed more than 360 times higher than this in the 16 installations sampled in
the bricks sector, whereas an average aluminium producer responding to the
questionnaire pays 42.9 €/MWh that is 63.7 €/MWh less than an average bricks
producer responding to the questionnaire.
The finding is not surprising as possible
explanations for decreasing price levels associated to higher consumption
volumes include more favourable supply contracts (including long-term
contracts); discounts for large-scale consumers; different levels of levies and
taxes (incl. exemptions for large-scale consumers). It is worth noting that
these average prices represent the values aggregating the plants surveyed in multiple
countries with different price levels and different legislative frameworks.
Figure 28 Electricity
consumption range and price variations grouped by sector (89 plants)
Source: CEPS, calculations based on questionnaires
Table 4 Average electricity prices and median
consumption in various sectors (89 plants)
   || Bricks || Tiles || Glass || Amm. || Chlorine || Steel || Alum. 
 Average price (€/MWh) || 106.5 || 94.7 || 79.3 || 71.7 || 58.2 || 66.1 || 42.9 
 Median consumption  (GWh) || 5.3 || 12.7 || 27.4 || 83.2 || 384.8 || 436.0 || 1,915.0 
Source: CEPS, calculations based on questionnaires
In addition to EU averages data, a specific
assessment has also been conducted for four Member States - Germany, Italy,
Poland and Spain – using answers to industry questionnaires collected across
all sectors. This assessment builds on case study-based results that cannot be
extrapolated to the entire sectors in each of these Member States and are meant
to give insight about a sample of plants across the EU. Due to data limitations
and the need to ensure the anonymity of plants, the country-specific analysis
could be conducted only with regard to electricity prices and price components.

First, data shows a high variation of
electricity prices paid by certain operators in the
four Member States. It shows a general increase in prices in the 28 plants
surveyed in Italy and Spain, a stable price level in Poland and a decrease in
Germany.
Amongst the four selected countries and the
28 facilities in the industrial branches sampled, the 5 producers located in
Italy face the highest price. Despite the fact that the selected plants in
Italy have an average consumption similar to that of plants in Spain (23 vs. 14
GWh/year) Italian producers still paid about 20 €/MWh more than Spanish
producers. A major part of this difference is due to higher impact of the
energy component in Italy.
In contrast to the other countries
analysed, the 10 Spanish electricity consumers in the present sample do not
directly pay the costs for RES support through levies[51].
RES levies appear to have an impact also in
the plants surveyed in Poland, where they represent about
10% of the final price paid the sampled plants.  However, compared to the 15
plants in Italy and Spain, the 5 plants in Poland face lower or
considerably lower grid fees. The latter are even lower in Germany, where they account for only about 6% of final
electricity price in 2012 for the 8 installations sampled.
Among possible explanations of lower grid fees in both Poland and Germany,
there is also the possibility that some of the sampled plants are
connected to the high-voltage grid.
For the 8 German plants surveyed, the
average price decreased from 2011 to 2012. This was associated with the
decrease of three out of the four components assessed, namely grid fees, RES
levies and energy component. However, it is
worth noting that a certain share of grid fees is charged in the country in
relation to the connection power of the consumer (i.e. euro per watt peak) and
is not related to annual consumption. Therefore, increasing the annual
consumption would decrease the grid fees when expressed in EUR/MWh, as reported
in the graph below. Admittedly, it is still probable that one or more plants in
Germany have benefited from lower grid fees starting
in 2012. Atypical and energy intensive electricity consumers were exempt from
grid fees in the order of 340 million Euro[52]. Decreasing RES levies are associated to new exemptions
granted in that year, reversing the previous increasing
trend.
At the same time, the reasons behind the
slight decrease in the energy component may be related to the falling wholesale
market prices in Germany driven significantly by the strong growth in wind and
solar electricity production.
Figure 29 Structure of electricity costs in Italy, Spain, Germany and Poland in
absolute terms (28 plants) (€/MWh)
Source: CEPS, calculations based on questionnaires. 
Figure 30 Structure of
electricity costs in Italy, Spain, Germany and Poland in relative terms (28
plants) (%)
Source: CEPS, calculations based on questionnaires.
As indicated above in the methodological
section (Annex 2), all prices presented are net of possible exemptions from
taxes, levies or transmission costs. In Table 5, the full size of the RES levies are
compared with the average values paid by the sampled plants. The figures show
that the sampled German plants received – on average – a 93% reduction in the
year 2012.
Table 5– RES levies in
Germany – regular vs. average values paid by sampled plants (€/MWh)
   || 2010 || 2011 || 2012 
 RES levy (regular, full size) || 20.47 || 35.30 || 35.92 
 RES levy (average sampled plants) || 2.6 || 3.3 || 1.8 
Source:
CEPS, calculations based on questionnaires

1.1.2.1.                  
Bricks and roof tiles

The results of the case study for bricks
and roof tiles presented below are based on the answers provided by a sample of
13 plants to a questionnaire and to each sections of it, as reported in the
table below. The share of the sampled plants in EU production is unknown.
Production volumes are reported using different units due to homogeneity of
products.
Table 6 – Number of
questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison 
 23 || 13 || 13 || 13 || 8 || 6 
Average electricity prices for the sample
of bricks and roof tiles producers have increased by about 13% between 2010 and
2012, from 90.4 to 102.4 €/MWh. The spread between the lowest and the highest
price in the sample has also increased by 40%, going from 91.4 to 128 €/MWh,
indicating an increased variability across sampled operators. In particular,
the gap has been widening because of the sustained increase of the maximum
price recorded (+30%). Very different price dynamics can be observed across
regions.
Table 7 Descriptive statistics for electricity prices paid by the 13 sampled
brick and roof tile producers in the EU (€/MWh)
 Electricity price (€/MWh) €c/kWh || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 90,4 || 93,4 || 102,4 || 13,3 
 EU minimum || 52,7 || 54,1 || 58,7 || 11,4 
 EU maximum || 144,1 || 146,1 || 186,7 || 29,6 
 Northern Europe (average) || 89,9 || 91,3 || 95,0 || 5,7 
 Central Europe (average) || 95,4 || 99,3 || 103,4 || 8,4 
 Southern Europe  (average) || 87,1 || 89,2 || 105,0 || 20,6 
Northern Europe includes 5 plants: IE, UK,
BE, LU, NL, DK, SE, NO, LT, LV, FI, EE
Central Europe includes 3 plants: DE, PL, CZ, SK, AT,
HU
Southern Europe includes 5 plants: FR, PT,
ES, IT, SI, HR, BG, RO, EL, MT, CY
Note that sampled plants do not come from
all the Member States in one region. The specific countries cannot be indicated
due to confidentiality reasons.
Source: CEPS, calculations based on questionnaires
In 2010 based on the sample of plants
surveyed Southern Europe represented the region with lowest average price.
Between 2010 and 2012 the 5 plants in Southern Europe saw a sustained increase in
electricity prices of more than 20%. As a result of this, in 2012 Southern
Europe was the region with the highest average electricity price (105 €/MWh
compared to 103.4 and 95 €/MWh for Central and Northern Europe, respectively).
In terms of electricity price components,
energy still represents the most significant one in the 13 sampled plants.
However, despite a slight increase between 2010 and 2012 - from 58.3 €/MWh
to 59.9 €/MWh – its share of the total price has decreased from 65% to 58%.
This development is related to the stronger increase in other components. 
This is due to the significant increase in
all other components, with grid fees going up by 21% in the plants surveyed (from
17.6 to 21.3 €/MWh), other non-recoverable taxes and levies increasing by 28.4%
(from 8.1 to 10.4 €/MWh) and RES levy by 73.0% (from 6.3 to 10.9 €/MWh). Between
20120 and 2012, the share of components other than energy in the total average
electricity price went up from 35% to 42%.
Figure 31 Components of the electricity bills
paid by the 13 sampled bricks and roof tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Looking at the trend in the plants surveyed
in different regions, RES levies registered a much higher increase in the
plants surveyed both in Southern and in Northern Europe compared to Central
Europe (127%, 114% and 41% respectively). Despite the different dynamics,
however, the impact of RES levies on final price remained greater in the
Central Europe where they represented 17% of the total.
The non-recoverable tax component increased
considerably in the plants surveyed in Central Europe (+57%) while only
slightly increasing (+13%) or remaining stable in the plants in Southern and
Northern Europe, respectively.
Finally, grid fees went up by 54% in the
plants surveyed in Southern Europe compared to slight decrease or increase
elsewhere, therefore, pushing up the EU average.
Figure 32 Components of the electricity bills
paid by the 13 sampled bricks and roof tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.

1.1.2.2.                  
Wall and floor tiles

The results of the case study for wall and
floor tiles presented below are based on the answers provided by a sample of 12
plants to a questionnaire and to each sections of it, as reported in the table
below. The share of the sampled plants in EU production could not be
calculated. Production volumes are reported using different units due to
homogeneity of products.
Table 8 – Number of
questionnaires used in the wall and floor tiles case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and margins 
 24 || 12 || 12 || 12 || 6 || 6 || 9 
The average electricity price paid by the
sample of 12 wall and floor tiles producers has increased by more than 20%
between 2010 and 2012, from 80.8 to 97.6 €/MWh. The spread between the lowest
and the highest price has also increased by about 37%, going from 63.5 to 86.8
€/MWh, indicating an increased variability across operators.
Table 9 Descriptive statistics for electricity prices paid by the 12 sampled
EU wall and floor tile producers (€/MWh)
 Electricity price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 80,8 || 88,8 || 97,6 || 20,8 
 EU minimum || 64,1 || 71,4 || 76,9 || 20,0 
 EU maximum || 127,6 || 130,3 || 163,7 || 28,3 
 Central and Northern Europe (average) || 74,4 || 86,3 || 92,0 || 23,7 
 South-Western Europe (average) || 85,3 || 89,5 || 92,9 || 8,9 
 South-Eastern Europe (average) || 99,5 || 103,6 || 120,1 || 20,7 
Central and Northern Europe includes 3
plants: IE, UK, BE, LU, NL, DK, DE, PL CZ, LV, LT, EE, SE, FI
South-Western Europe includes 5 plants: ES,
PT, FR
South-Eastern Europe includes 4 plants: IT,
SI, AT, HU, SK, HR, BU, RO, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires
With regard to the regions assessed, the
strongest increase in electricity price was registered in the 3 plants based in
Central and Northern Europe (23.7%), which led to an average price in 2012 in
line with the price paid by 5 plants in South-Western Europe. However, in each
of the years observed, the highest price of electricity is paid by operators in
South-Eastern Europe, which paid 120 €/MWh in 2012 (up by 21% compared two
2010).
With regard to the electricity price
components in the 12 sampled plants, energy still represents the most
significant one although, despite an increase in absolute terms of about 9%,
its relative weight for the whole sample decreased from 70% in 2010 to 63% two
years later. The result is mainly the consequence of the strong increase of the
RES levy component, which more than doubled over the period, going from 6.7
€/MWh in 2010 to 14.7 €/MWh in 2012 (+119%). The other components, namely grid
fees and other non-recoverable taxes also increased but at a lower pace (about
20%), resulting in a rather stable share over the total price.
Figure 33 Components of the electricity bills
paid by the 12 sampled wall and floor tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Looking at the trend in different regions,
RES levies registered a very high increase in the plants surveyed in both
Central and Northern Europe and in these based in South-Eastern Europe (101%
and 141%, respectively). The relative weight of the RES component in the two
regions therefore went up to about 20%. 
However, in the sample of plants located in
South-Eastern Europe a 34% decrease in other non-recoverable taxes is observed
(from 4.4 €/MWh in 2010 to 2.9 €/MWh in 2012) while these increase in Central
and Northern Europe and remained fairly stable in South-Western Europe. The
size of RES contributions in South-West Europe could not be established based
on the invoices provided by respondent plants. 
Grid fees increased in all three regions,
with the highest increase registered in South-Eastern Europe (about 16%).
Figure 34 Components of the electricity bills
paid by the 12 sampled wall and floor tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.

1.1.2.3.                  
Float glass

The results of the case study for float
glass presented below are based on the answers provided by a sample of plants
to a questionnaire and to each sections of it, as reported in the table below.  The
10 plants in the sample represent about 19% of European production. 
Table 10. Number of questionnaires used in the
float glass case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs || Margins 
 10 || 10 || 10 || 7 || 10 || 7 || 4 
Average electricity prices in the sampled
plants were on the rise in the period 2010-2012. These increased by about 10%
between 2010 and 2012, from 76.7 to 84.3 €/MWh. The spread between the lowest
and the highest price is considerably high and has further increased, going
from 60 to 82 €/MWh (+37%).
Different price dynamics can be observed
across regions. In particular the increase is particularly evident for the 2
sampled operators in Southern Europe, which already paid the highest price in
2010 and in 2012 paid almost twice as much as the 2 plants in Eastern Europe.
Table 11 Descriptive statistics for electricity prices paid by the 10 sampled
EU float glass producers (€/MWh)
 Electricity price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 76,7 || 79,3 || 84,3 || 9,9 
 EU minimum || 50,6 || 50,5 || 55,1 || 8,9 
 EU maximum || 110,0 || 113,9 || 136,6 || 24,2 
 Western Europe (average) || 78,3 || 80,4 || 83,9 || 7,2 
 Southern Europe (average) || 93 || 96,7 || 110,3 || 18,6 
 Eastern Europe (average) || 59,1 || 62,6 || 64,7 || 9,5 
Western Europe includes 6 plants: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes 2 plants: BG, RO,
CZ, HU, EE, LT, LV, SK, PL
Southern Europe includes 2 plants: IT, MT,
CY, PT, ES, EL, SI
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires.
The energy component is the largest
component, with a share of about 71% of the total. Based on the 10 sampled
plants, between 2010 and 2012, the energy component has increased by 8%, from
52 €/MWh to 56.1 €/MWh. Over the same period different trends can be
observed for the other price components. In particular, in the plants surveyed grid
fees increased overall by 11% after a decline between 2010 and 2011. At the end
of the period their share of total price results only slightly higher compared
to the previous year but still in the range of 15%.
The average of RES levies increased by 37%
between 2010 and 2011 but decreased afterwards and led to a slight reduction in
the relative share of RES in the total price since 2010 (from 12% to 11%). In
contrast, other non-recoverable taxes and levies decreased between 2010 and
2011 and then decreasing the following year, registered an overall decrease of
about 3% at the end of the period.
Different trends can be observed across
regions. In fact, while for the 6 plants in Western Europe the average RES levy
and other non-recoverable taxes decreased both in absolute and relative terms,
in the 2 plants in Eastern Europe the same components increased in absolute
terms by 51% and 64%, respectively, therefore resulting in a higher weight on
total price.
In 2012, components other than energy
(production costs) in the 2 Eastern European plants accounted on average for
about 35% of the total electricity price, compared to 30% in 2010.
Figure 35 Components of the electricity bills
paid by the sampled float glass producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 36 Components of the electricity bills
paid by the sampled float glass producers in Europe %)
Source: CEPS, calculations based on questionnaires.

1.1.2.4.                  
Ammonia 

The results of the case study for ammonia
producers are based on the answers provided by a sample of plants to a
questionnaire and to each section of it, as reported in the table below. 
The 10 sampled plants represent in total about
26% of EU27 production. Considering that about 80% of the global ammonia
production is used for the production of fertilisers, the case study focused on
ammonia plants that in the vast majority of cases are integrated in large
installations that subsequently produce fertilisers. The sample includes 2
small, 4 medium and 4 large-sized plants. The 10 plants are located in 10
different member states.
Table 12 Number of questionnaires used in the ammonia case
study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs 
 10 || 10 || 10 || 10 || 10 || 7 
Natural gas is the predominant fuel used by
the sampled plants, accounting for about 90-94% of their total energy costs. Electricity
accounts for about 4-8% of total energy costs of the sampled plants.
Data collected show that the average price
of electricity paid by the sampled producers of ammonia has increased by 11%
between 2010 and 2012, from 63.9 to 71.1 €/MWh. The gap of prices paid by sampled
producers has also increased.
From the 10 sampled plants, similar price
increases can be observed in all the geographical regions defined, in line with
the EU average. Nevertheless, the surveyed plants in Southern Europe witnessed
the highest price throughout the 3-year period assessed.
 
Table 13 Descriptive statistics for electricity prices paid by 10 sampled ammonia
EU producers (€/MWh)
 Electricity price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU (average) || 63.9 || 72.5 || 71.1 || 11.3 
 Western-Northern Europe (average) || 54.0 || 62.4 || 61.0 || 13.0 
 Southern Europe (average) || 86.3 || 95.5 || 96.0 || 11.2 
 Eastern Europe (average) || 64.3 || 73.6 || 70.7 || 10.0 
Western-Northern Europe includes: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes: RO, CZ, HU, EE, LT,
LV, SK, PL
Southern Europe includes: IT, MT, CY, PT,
ES, EL, SI, BG
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons. The number of sampled plants per region cannot be
disclosed due to confidentiality.
Source: CEPS, calculations based on questionnaires.
With regard to the different price
components, the energy part accounts for more than 60% of the total price. Between
2010 and 2012, the energy component increased on average for the whole sample
by 12%, from 47.1 to 52.9 €/MWh
For the 10 sampled plants other
non-recoverable taxes remained stable both in absolute terms (around 1.6-1.8
€/MWh) and as a share of total price (2.5%). The contribution of RES levies in
the total bill has steadily increased from 5.6% in 2010 to 8% in 2012, reaching
5.7 €/MWh in absolute terms in 2012. As for the grid fees, their impact on the
total bill decreased from 17.1% in 2010 to 15.5% in 2012. Their absolute value
remained almost stable between 2010 and 2012 (around 11€/MWh).
Over the period, the plants in Southern
Europe experienced the highest impact of RES levies on the total energy bill.
In absolute terms, RES levies increased from 7.17 €/MWh in 2010 to
11.37 €/MWh (+59%) in 2012. The plants in Eastern Europe experienced the
highest increase of RES levies, from 1.95 €/MWh in 2010 to 8.33 €/MWh in 2012,
with their contribution to the bill increasing from 3.2% in 2010 to 11.8% in
2012.
Figure 37 Components of the electricity bills
paid by the 10 sampled ammonia producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 38 Components of the electricity bills
paid by the 10 sampled ammonia producers in Europe (%)
Source: CEPS, calculations based on questionnaires.

1.1.2.5.                  
Chlorine

The results of the case study for chlorine
producers presented below are based on the answers provided by a sample of
plants to a questionnaire and to each sections of it, as reported in the table
below. The 9 sampled plants represent about 12% of EU27 production. The
membrane manufacturing technology represents 62% of the capacity of the plants
in the sample, the mercury technology 32% and others 6%. The diaphragm
technology is not represented in the sample.
Table 14 Number of questionnaires used in the chlorine case
study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs 
 11 || 9 || 9 || 9 || 9 || 5 
Electricity is the predominant fuel of the
9 sampled plants and accounts for about 91% of total energy costs[53] and for 43-45% of total production costs[54] of the sampled plants. All sampled chlorine producers use
electricity as a primary source of energy, while some use steam as a secondary
energy carrier[55].
The average price of electricity paid by
the sampled chlorine producers increased slightly between 2010 and 2011, and
then decreased in 2012.Overall, between 2010 and 2012 the average electricity
price fell by 5%, from 59.4 to 56.4 €/MWh. This result is a weighted average
and strongly influenced by the trend registered in the 6 plants in Central-Northern
Europe, which contains a higher share of the total sampled production capacity.
The average price paid by the 6 operators in this region decreased by about 10%
(from 60.3 to 54.1 €/MWh) while the price observed in the 3 sampled plants in Southern-Western
Europe registered a very significant increase (40%) and in 2012 was 1.3 times
higher than the average price in Central-Northern Europe.
With regard to the different price
components, the energy part slightly decreased in absolute terms between 2010
and 2012, from 48.7 to 48.9 €/MWh, although its relative share of the total
electricity price increased to almost 87%.
For the sampled plants grid fees and RES
levy also decreased over the period assessed: grid fees from 6.9 to 5 €/MWh
(-29%), RES levy from 2.5 to 1 €/MWh (-59%), which for both components is
associated with a reduction in their relative share of the total price (from
11.7% in 2010 to 8.8% in 2012 for grid fees and from 4.2% in 2010 to 1.8% for
RES).
Table 15 Descriptive statistics for electricity prices paid by the 9 sampled
EU producers of chlorine (€/MWh)
 Electricity price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 59.4 || 59.8 || 56.4 || -5.1 
 Southern-Western Europe (average) || 51.9 || 61.5 || 72.7 || 40,1 
 Central-Northern Europe (average) || 60.3 || 59.5 || 54.1 || -10.3 
Central-Northern Europe includes 6 plants:
IE, UK, BE, LU, NL, DE, PL, CZ, LV, LT, EE, DK, SE, FI
Southern-Western Europe includes 3 plants:
ES, PT, FR
For remaining MS, no questionnaires were
received and no averages could be calculated.
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons. 
Source: CEPS, calculations based on questionnaires.
On the contrary, although still having a
relatively small impact on total price (2.5% in 2012), other non-recoverable
taxes registered a significant increase from 0.2 to 1.4 €/MWh. 
Looking at regional averages, one can
observe a 25 fold increase of non-recoverable taxes in the 3 Southern-Western
European plants, from 0.44 to 10.5 €/MWh between 2010 and 2012. As a
consequence, their weight on total electricity price paid by the sampled plants
went up from less than 1% to more than 14%. In the same region, the energy
component increased also substantially in absolute terms, from 42.5 to 54.2
€/MWh (+28%) while other components decreased both in absolute terms and as a
share of total price.
As observed before, in the 6 plants in Central-Northern
Europe the overall average electricity price decreased between 2010 and 2012.
Looking at the different components, one can see that all components decreased
except non-recoverable taxes, which remained stable and with a very limited
share of total price.
Figure 39 Components of the electricity bill
paid by the 9 sampled chlorine producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 40 Components of the electricity bill
paid by the 9 sampled chlorine producers in Europe (%)
Source: CEPS, calculations based on questionnaires.

1.1.2.6.                  
Steel

The results of the case study for steel
producers are based on the answers provided by a sample of 17 plants, out of
more than 500 steel plants in the EU. The sample
installations were self-selected by the industrial sector.
Steel making plants can be broadly
classified in two different groups, integrated plants and mini-mills. The
former use Basic Oxygen Furnaces (BOFs) to transform iron ore and coke into
steel. Mini-mills are plants comprising only steel furnaces and rolling and
finishing facilities. Mini-mills generally use Electric Arc Furnaces (EAFs) to
produce steel and mainly rely on scrap rather than raw iron, which is usually
purchased as processed input. The results of the case study for steel producers
are based on the answers provided by a sample of plants to a questionnaire and
to each sections of it, as reported in the table below[56]. For each technology, sampled plants had different capacity in
order to reflect a distribution similar to that of the steel making universe. 
The 4 BOF plants included in the sample
range from small to medium (up to 4.5 MMt), while very large BOF plants are not
covered. The 9 EAF plants included are very diversified in terms of capacity,
ranging from small (< 400 thousand tonnes) to large (> 1.3MMt). Consumption
of electricity for steel making is very different between BOFs and EAFs.
Electricity intensity of the BOF process is about one third of EAF;
furthermore, BOF installations usually include a self-generation facility,
where electricity is produced out of recycled waste gases from the furnaces.
This means that on average sampled BOF producers procure electricity from
external sources for about 60% of their total electricity consumption. Once
these factors are accounted for, the sample points to the fact that much
smaller EAF installation consumes as much electricity as larger BOF ones.
Consumption levels for the 9 EAF plants in
the sample range between 150 and 600 GWh per year; as for the 4 BOF plants, the
range is between 350 and 750 GWh per year. Given that the production process is
standardised, the biggest determinant of electricity consumption is plant
capacity, and the presence of hot or cold rolling facilities within the plant
premises.
Table 16 Number of questionnaires used in the steel case
study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and Margins 
 17 || 17 || 15 (gas) 17 (electr.) || 14 (gas) 17 (electr.) || 11 (gas) 14 (electr.) || 3 || * 
* Data available from the Cumulative cost
Assessment Study (CEPS)
Compared to natural gas, both EU average
and EU median electricity prices paid by the 17 sampled steel plants are more
stable. EU sample price went up by 7% from 66.8 to 71.4 €/MWh.
Different geographical regions have all
registered an increasing trend although of different intensity, as it can be
seen from the table below:
Table 17 Descriptive statistics for electricity prices paid by 17 sampled EU
producers of steel (€/MWh)
 Electricity price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU (average) || 66,8 || 71,2 || 71,4 || 6,9 
 EU (minimum) || 51,8 || 51,0 || 46,5 || -10,2 
 EU (maximum) || 89,6 || 93,5 || 104,4 || 16,5 
 Central and Eastern EU (average) || 77,7 || 84,7 || 92,5 || 19,0 
 Southern EU  (average) || 67,7 || 68,8 || 74,2 || 9,6 
 North-Western EU  (average) || 60,7 || 64,3 || 59,4 || -2,1 
 BOF Average || 67,5 || 73,9 || 73,9 || 9,5 
 EAF Average || 65,2 || 67,0 || 67,0 || 2,8 
North-Western Europe includes 9 plants: FR,
BE, LU, NL, IE, UK, DE, AT, DK, FI, SE
Central and Eastern Europe includes 3
plants: PL, SI, HU, RO, BG, CZ, SK, EE, LV, LT
Southern Europe includes 5 plants: IT, ES,
PT, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires.
The energy component is the most
significant component of the electricity price paid by the sampled production
facilities in Europe. In 2010, the energy component of
the electricity price paid by the 17 sampled plants amounted to 53.9 €/MWh
(81% of price) and decreased to 53.3 €/MWh in 2012 (-0.1%). However, its share
over the total costs shrank from 81% to 74% due to the increase of the other
components, mostly RES levies. RES levies reached 8.8 €/MWh (+91%), and in 2012
they represented 12% of the final electricity bill. Network costs and other
taxes and levies increased by 24% and 10%, respectively. Note that the steel
industry is outside of the scope of the Energy Taxation Directive. 
Figure 41 Components of the electricity bills
paid by the 17 sampled steel producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 42 Components of the electricity bills
paid by the 17 sampled steel producers in Europe (%)
Source: CEPS, calculations based on questionnaires.

1.1.2.7.                  
Primary aluminium

The evidence presented in the case study
for aluminium is based on data collected via a questionnaire from a sample of
11 out of the 16 primary smelters in the EU, representing more than 60% of EU
primary aluminium production in 2012. The data has been validated using the CRU
database[57]. 
In contrast to other case studies in this
report, no sampling by geographical region is presented. The averages
calculated for the whole sample are compared to averages obtained for two subsamples
which are of great importance for understanding the issue of energy costs
impact on the sector. In particular, subsample 1 refers to 5 plants which
procure electricity through long-term contracts or self-generation[58] while subsample 2 refers to 6 plants which procure electricity in
the wholesale market.
In terms of price per MWh, the 2012 average
price is 44.7 €/MWh[59]. A wide range of diversity is seen in the actual price paid by
individual plants in the sample, which can be explained by considering the two
main forms of procuring electricity. The average electricity cost for subsample
1 is 24.3 €/MWh while for subsample 2 it is 56 €/MWh, more than 2.3 times
higher. 
Smelters with low electricity prices (subsample
1) are mainly those which are in a long-term electricity contract or which have
their own generation (the minority in subsample 1). These contracts are considered
to be non-replicable. As soon as these contracts come to an end, these smelters
are expected to move up the electricity price curve and reach the electricity
price level of the smelters in subsample 2. Smelters in subsample 2 buy
electricity on the market and are impacted by differences in terms of wholesale
prices on different markets, national policies, energy mix, grid costs, or
other tariffs.
Figure 43 Prices of electricity for the 11 sampled
aluminium smelters - 2012 ($/MWh, delivered at plant)
Source: CEPS, calculations based on questionnaires and
CRU. Note: plant 8 is now
closed.
Plants in subsample 1 are shielded from
transmission costs and other taxes while the impact of RES levies is minimal,
only slightly increasing from 0.7% to 1.5% of total price between 2010 and
2012.
For plants in the subsample 2, the sum of
all components other than energy increased from 8.8% to 10.4% of the total
price over the observed period. In particular, the increase is due to the
upward trend registered for RES levies, which increased by more than 370%
between 2010 and 2012 (from 0.6€/MWh to 2.9€/MWh). Transmission costs decreased
by almost 30%, as a consequence of a decrease in two smelters; for all
remaining smelters the component remained stable. Other taxes remained stable
both in absolute terms as well as share of total price.
Figure 44 Components of the electricity bills
paid by the 11 sampled aluminium producers in Europe (€/MWh)
Note: A certain degree of estimation is
included because of the different possibility of singling out all components
for all sampled plants.
Source: Calculations based on
questionnaires
Figure 45 Components of the electricity bills
paid by the 11 sampled aluminium producers in Europe (%)
Note: A certain degree of estimation is
included because of the different possibility of singling out all components
for all sampled plants.
Source: Calculations based on
questionnaires
[1] Including seven energy intensive industries: bricks and roof tiles,
wall and floor tiles, float glass, ammonia, chlorine, primary aluminium and
steel
[2] Overnight cost is the cost of a construction project if no interest
was incurred during construction, as if the project was completed
"overnight". It is the value of the investment project to be paid
upfront as a lump sum that would cover the construction costs (including
pre-construction costs and Engineering, Procurement and Construction (EPC)
costs) and any additional contingency costs.
[3] Communication from the Commission on delivering the internal
electricity market and making the most of public intervention http://ec.europa.eu/energy/gas_electricity/doc/com_2013_public_intervention_en.pdf

[4] The limiting values for the consumer bands are as follows:
Electricity households DC 2 500 kWh < Consumption < 5 000 kWh.
Electricity industrial IC 500 MWh < Consumption < 2 000 MWh. Natural gas
households D2 20 GJ < Consumption < 200 GJ equivalent to 5.56 MWh <
Consumption <  55.56 MWh. Natural gas industrial I3 10 000 GJ <
Consumption < 100 000 GJ equivalent to 2.78 GWh <  Consumption < 27.78
GWh
[5] Industrial prices reported in line with Directive 2008/92/EC on
industrial electricity and gas price data collection may include other
non-residential user. In the case of gas all industrial uses are considered.
However, the system excludes consumers who use gas for electricity generation
in power plants or in CHP plants, in non-energy uses (e.g. in the chemical
industry), above 4,000,000 GJ/y.
[6] For example  Directive 2008/92/EC. paragraph (m) of Annex I and II
specifies that taxes, levies, non-tax levies, fees and any other fiscal charges
not identified in the invoices provided to industrial end-users go under the
reported figures for the price level ‘Prices excluding taxes and levies’.
[7] The purchasing power standard, abbreviated as PPS, is an artificial
currency unit. Theoretically, one PPS can buy the same amount of goods and
services in each country. However, price differences across borders mean that
different amounts of national currency units are needed for the same goods and
services depending on the country. See more at http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Glossary:Purchasing_power_standard_(PPS). Purchasing power parities, abbreviated as PPPs, are
indicators of price level differences across countries ,see more at 
http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Glossary:Purchasing_power_parities_(PPPs)
[8] European Commission, DG ECFIN,
Market functioning in network industries, Occasional Paper 129, February 2013.
[9] The variation coefficient is a normalized
measure of dispersion. It is defined as the ratio of the standard deviation to
the mean. The higher the ratio, the more dispersed the data.
[10] The dispersion reported for 2010 refers to the average revenue per
minute of mobile communications, whose definition is slightly modified with
respect to the former: nevertheless, its commonality among Member States should
not justify significant changes in the dispersion thereof. More information
available in Annex 1 of the report mentioned in the footnote above.
[11] To be published by DG Health and Consumers
during the first semester of 2014
[12] Median household consumer band with annual consumption between 2
500 and 5 000 kWh per year. Prices measured in cents EUR / kWh.
[13] Second round effects in the interaction of retail electricity
prices and inflation (the electricity price being a component of the HICP) are
not discussed in this report.
[14] These countries may give exemptions that are not uniform and hence
report certain levies as non-recoverable, whereas they are indeed recoverable
for certain categories of consumers. 
[15] The Spanish data apparently includes
significant other charges together with network costs
[16] A combination of an increase in VAT rate, concession fees, stranded
costs and other taxes linked to the energy sector and a small decreases on RES
and CHP levies and the compensation for isolated islands, according to the MS
metadata (see footnote Error! Bookmark not defined.)..
[17] The RES tax doubled and the VAT rate increased more than 4 time,
according to the MS metadata (see footnote Error! Bookmark not defined.).
[18] http://www.energypriceindex.com/

[19] The prices for the industrial consumer bands are net of VAT and
other recoverable taxes and levies.
[20] Source: MS metadata (see footnote Error! Bookmark not defined.).
[21] Excluding VAT and other recoverable taxes
[22] These indices are a proxy for the spot price; they are also used to
build derivative products on the forward curve. Finally, they serve as a
reference point for the over-the-counter trade (cleared  and non-cleared).
[23] “European power trading 2013”, Prospex Research, www.prospex.co.uk 
[24] The churn facto is defined as the ratio of traded volume to
physical consumption. It informs about the liquidity of the market place and
the quality of the pricing signal that is discovered on that market.
[25] Negative prices occur when, with excess supply of electricity,
utilities with inflexible generation capacity prefer to pay to sell the
generated electricity, rather than ramp down or close their power stations
[26] The ranking of electricity generation assets by their marginal cost
of production sets up the supply curve, also known as the merit order.
[27] The part of the consumer bill related to the supply of energy is in
fact the only component where suppliers can actually compete.
[28] The report is available here: http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER%20Market%20Monitoring%20Report%202013.pdf

[29] The functioning of retail electricity markets for consumers in
the European Union, Study on behalf of the European Commission, Directorate-General
for Health and Consumers, 2010 –  
http://ec.europa.eu/consumers/consumer_research/market_studies/docs/retail_electricity_full_study_en.pdf.
[30] DG ECFIN. Energy Economic Development in Europe
[31] The Consumer Markets Scoreboard ranks over 50 consumer markets
based on how well they are functioning for consumers in terms of trust,
comparability, problems and complaints and overall consumer satisfaction. In
addition, for the relevant markets, the Scoreboard also monitors switching
suppliers and tariffs and consumer choice of providers. See
http://ec.europa.eu/consumers/consumer_research/cms_en.htm.
[32] There is a 33 point difference (on a scale for up to 100 points)
between the top ranked country (Germany) and the bottom ranked country
(Bulgaria).
[33] Consumer Market Monitoring Survey 2013 commissioned
by DG SANCO, to be used in the forthcoming 10th Consumer Markets Scoreboard.
[34] See Energy Economic Development in Europe, DG ECFIN. 
[35] A first estimation
of the total length is provided by Eurelectric, “Power distribution in Europe:
facts and figures”: 
http://www.eurelectric.org/media/113155/dso_report-web_final-2013-030-0764-01-e.pdf

[36] https://www.entsoe.eu/fileadmin/user_upload/_library/Market/Transmission_Tariffs/Synthesis_2013_FINAL_04072013.pdf

[37] 2006/112/EC
[38] Includes CO2 tax in the case of Denmark, as reported for
the compilation of the Excise Duty Tables published by the European Commission
and available at http://ec.europa.eu/taxation_customs/resources/documents/taxation/excise_duties/energy_products/rates/excise_duties-part_ii_energy_products_en.pdf
[39] The study examined the following sectors: iron and steel;
aluminium; cement; chemicals, in particular chlor alkali, fertiliser and
industrial gases.
[40] Denmark, France, Germany, Italy and the UK,
[41] OECD. 2013. Taxing Energy Use: A Graphical Analysis.
[42] The law covers: electrolysis, glass, ceramics, cement, lime,
metals, fertilizers and chemical reduction methods. The industrial gas sector
qualifies for a reimbursement of 90%.
[43] Exemptions are granted to EIIs meeting the following conditions:
(a) the ratio of the electricity costs to gross value added exceeds 15% and
electricity demand exceeds 10 GWh/year at a certain delivery point; in which
case the added costs to the client cannot exceed €0.05 cents per kilowatt-hour;
(b) the ratio of the electricity costs to gross value added is below 20% and
the electricity demand is below 100 gigawatt-hours the limitation of the added
cost will only apply to 90% of the electricity purchased in the previous year.
[44] Qualifying sectors must meet the following criteria: (a) energy
intensity (EI) must be 3% or more (i.e. energy costs must be 3% or more of the
production value for the sector); (b) the industry import penetration ratio
must be 50% or more - this ratio is calculated for the sector as a whole to
determine its exposure to international competition. Sectors that do not meet
the international competitiveness criteria must have an EI of 10% or more.
Source: https://www.gov.uk/climate-change-agreements

[45] ICF International. 2012. An international comparison of energy and climate change policies
impacting energy intensive industries in selected countries.
[46] OECD, ibid
[47] OECD, ibid
[48] OECD ibid
[49] "Composition and drivers of energy prices and costs in energy
intensive industries" Specific contract No SI2.6575586 with the Centre for
European Policy Studies. 
[50] The median refers to the value which splits
the sample in half; the box plot indicates the range of values between which
50% of the data sample lay.
[51] The Spanish government sets a so-called access fee (“peaje de
acceso”) to cover all costs that are not related to (conventional) production
and commercialisation. Costs for RES support are therefore supposedly included
in the other components but may also partly be covered by the public budget.
[52] See Federal Ministry of Economics and Technology (BMWi), Federal
Ministry for the Environment, Nature Conservation and Nuclear Safety (BMU:
First monitoring report "Energy of the future", Berlin 2012. 
[53] Average for the nine sampled plants.
[54] Average for the five plants that provided data on production costs.
[55] The number of data points was too low to allow for an analysis of
steam as a secondary energy carrier. Natural gas is used by only one plant in
the sample. For these reasons, the analysis is limited to electricity prices
and costs (chapter 2).
[56] In the sample, both technologies are represented, as 4 BOF and 9
EAFs are included plus two national representative facilities mostly referring
to EAF producers and two rolling mills. EAF plants, given their higher
electricity intensity per tonne of steel and the fact that do not own
self-generation facilities running on waste gases, are mostly exposed to the
costs of energy.
[57] CRU Group in an independent, privately owned company providing
business intelligence services on the global metals, mining and fertilizer
industries.
[58] The case of long-term contracts is the most frequent.
[59] Average weighted by 2012 production.
EUR/USD exchange rate: 1.2848. 2012 annual value, source ECB.

1.2.   Developments
in the retail markets for natural gas

Retail natural gas prices expressed in Euros
From 2008 until 2012, natural gas prices
for household consumers increased in every country of the EU except for Germany and Romania.  Europe's gas prices have risen by more than 3% a year between 2008
and 2012[1]. Bulgaria, Estonia and Spain registered annual price increases
close to 10% and growth rates in Lithuania and Croatia were even higher,
reaching more than 12% and 14% respectively.
Figure 1.
Evolution of retail prices, natural gas, domestic and industrial consumers,
centsEuro / kWh
During the observed period, industrial
prices for natural gas (excluding VAT and other recoverable taxes and levies)
were much more stable, with an average annual increase for the EU being less
than 1%. In most Member States a similar trend was observed: prices would
decrease in 2008 – 2009 and then they would pick up. Yet, the growth rates
varied wildly across Member States. 
Over the whole period, natural gas prices
(measured in Euro) fell for industrial consumers in Belgium, the Czech
republic, Germany, Italy, the Netherlands, Romania and Slovakia whereas double
digit annual growth rates were registered in Bulgaria and Croatia, even though
from a relatively low basis.
Retail natural gas prices expressed in purchasing power standards
When the monetary measure is switched to
purchasing power standards (PPS), the ranking of Member States is changed with
countries from the Eastern part of the continent moving up in the ranking of countries with the highest prices. 7 out of the 10 Member States with the highest household prices
are such countries with the average consumers from Bulgaria paying the highest
price for natural gas.
Figure 2.
Evolution of retail prices, natural gas, industrial consumers, cents PPS / kWh
The same observation applies for industrial
consumers: the top 10 PPS rates are all paid by countries from the East. In the
second half of 2012 industrial consumers from Hungary, Lithuania, Croatia, Slovenia, Greece, Poland, Slovakia, Latvia and Romania were paying on average
higher gas prices than the countries from North West Europe; in Bulgaria industrial consumers were actually paying three times as much as in the UK.
These developments have clear negative
implications for the competitiveness of the economies of the new Member States
and point to the potential savings for final consumers if grids are integrated
and the competitive play of supply and demand is allow to set the prices.
Comparing
natural gas price changes to inflation levels
As shown on Map 1, during the observed period the
increase of median household consumer prices for natural gas outpaced the
increase of the general price level[2],
as measured by the harmonized index of consumer prices (HICP). Belgium, Germany, Romania, Slovenia and Slovenia were the exception to that rule.
The actual changes of natural gas and
general price levels in 2008 – 2012 were quite unique for each Member State and the map colours illustrate only the relative position of those changes.
Natural gas prices, measured in national currencies, all taxes included,
increased by more than 30% from 2008 to 2012 in Bulgaria, Estonia, Spain, Italy, Hungary and Portugal. In Lithuania and Croatia gas prices rose by 60% and 70%
respectively. For the same period, inflation levels increased by more than 10%
in Bulgaria, Estonia, Greece, Cyprus, Lithuania, Luxembourg, Hungary, Malta,
Poland, Romania, Slovakia, Finland and the UK.
In the case of industrial consumers (Map 2), the situation was quite
different. For the majority of Member States the price rise for gas was below
the industrial price levels, as measured by the producer price index. The
levels of producer price indices (PPI) and gas prices (excluding VAT and other
recoverable taxes and levies) were specific for each Member State. Gas price changes varied in a broad range from a 10 – 15 % decrease (Belgium, Czech
republic, Slovakia) to increases of up to 50% (Finland, Bulgaria) with an
outlier of 100% (Croatia).
Map 1 Household gas prices vs. inflation
(HICP)
Map 2 Industrial gas prices vs. inflation (PPI)
Comparing natural gas price changes to exchange rate variations
The exchange rate variations played similar
effects to the ones observed in retail prices for electricity. From 2008 to
2012 the Romanian Lei depreciated by a fifth of its value (21%) with respect to
the Euro and the natural gas price for households was kept stable in national
currency; as a result, it appeared that prices measured in Euro decreased by
18%. 
Polish and Hungarian currencies depreciated
by 19% and 15% respectively in 2008 – 2012. Natural gas price increases in
natural currencies were then stronger than those observed in Euro (12% and
36%).
Swedish natural gas prices increased by 25
% in 5 years when measured in Euro; their rise was more gradual if measured in
Swedish Kroners. The 9% appreciation of the national currency made the price
rise appear bigger in Euros, with negative implications for the energy intensive export oriented companies.

1.2.1.      Natural gas price developments by components

Components at the EU level
The next chart illustrates the evolution of
the average EU retail prices for natural gas for industrial and household
consumers weighted by the respective share of each Member State in both
consumption categories.
Figure 3
Evolution of EU retail price for natural gas (wtd avg) by components: levels,
selected household and industrial bands)
The data collected from Member States[3] indicates that, on EU level, the average gas bill for the median
industrial consumers remained stable around 4.5 cents EUR / kWh during the
period covering 2008 – 2012. The energy component accounted for 3 cents EUR
per kWh in 2008 and in 2012 but its relative share registered a slight decrease
(from 70% to 68%) as the network and taxation elements increased marginally to
11% and 18% respectively.
The average EU retail gas price for
household consumers followed similar developments, gaining half a cent EUR in 5
years and reaching close to 7 cents EUR per kWh. All components increased
by a small margin but the relative share of energy went from 59% to 56% as the
network and taxation elements grew faster, levelling at 21% and 23% in 2012.
The next chart illustrates that these
developments contrasted sharply with the ones observed for the electricity
bill. The component growth of the different elements of the gas bill was much
more homogenous and not a single element grew by more than 20%. 
As shown in the figure below, only the
energy component of the electricity bill registered moderate increases on a
similar scale to the one observed for all elements of the natural gas bill. 
Figure 4. EU28
weighted average retail prices for natural gas, 2008-2012 percentage change by
component 
Looking into the evolution of the average
EU gas bills through 2008 - 2012, it appears that household consumers witnessed
bigger increases for all components. As a result, the total bill increased by
9% for households as opposed to just 4 % for industrial consumers. 4 of these
percentage points were due to the lower rise of the energy component industry
and 1 was linked to the stronger increase of taxes and network costs for
domestic consumers.
Components
at national level
Similar to the case of electricity, the
broad EU numbers conceal a wide range of variation for the retail gas prices
across Member States. Figure 5 and Figure 6 trace the level and the relative
share of the price components for each Member State and for the median
household consumers in 2008 and in 2012.
Figure 5. Natural gas prices by component,
households, Eurocent/kWh (2012)
Note: No data was reported for: Austria (2008 and 2012), Cyprus (2008 and 2012), Finland (2008 and 2012), Greece (2008 and 2012), Luxembourg (2008) and Malta (2008 and 2012). Ireland reported only tax-related elements.
Figure 6. Natural gas prices, households,
relative share of components
Note. No data was reported for: Austria (2008 and 2012), Cyprus (2008 and 2012), Finland (2008 and 2012), Greece (2008 and 2012) and
  Malta (2008 and 2012). Ireland reported only tax-related elements, so
relative shares are not reported. * Luxembourg data is for 2009.
In 2012 the energy element varied between
1.5 Eurocent/kWh (Romania) and 5 Eurocent/kWh (Luxembourg) and accounted for
30-77% of the consumer price (with Spain and Denmark at the lower end and UK and Luxembourg at the higher end). Network costs ranged between 0.32 Eurocent/kWh (Estonia) and 4.9 Eurocents/kWh (Spain) and accounted for 6%-54% of the total price paid in these two
countries. Taxation ranged between 5% (UK) and 52% (Denmark) and was at levels
from 0.28 Eurocents/kWh (UK) to 5.66 Eurocents/kWh (Sweden).
At the European level, the energy-related
costs appreciated by 4.5% between 2008 and 2012 (Figure 7). On the Member State level however, the same element fluctuated in broad bands ranging from decreases by
20%-25% in Romania, Germany and Hungary[4],
to increases by more than 50% in Bulgaria, Lithuania and Luxembourg and reaching almost 100% in Croatia. 
Figure 7 Natural gas prices, households, 2008 – 2012 percentage change by
component
Note. * LU data is for 2009 as 2008 data is not
available
Whereas the variation ranges observed for
energy are comparable to the ones for networks, the retail price elements
related to taxation were again the ones to register the highest movements.
With regards to the percentage change in
the network component, the Member States were spread in a range from a 5%-10%
decrease in the UK, Romania and Luxembourg to increases above 50% in Estonia, Spain and the Netherlands.
With regards to the percentage change in
the taxation component, the majority of Member States witnessed an increase of
20% - 50%, the more notable exceptions being Germany and Luxembourg, where a modest decrease was observed and Estonia, Spain, Croatia and Lithuania where the tax-related costs for households rose by 50% - 80%. Latvia and Portugal were a special case where the taxation component grew by more than 300%, in both
cases due to a significant increase in the VAT rate (and a new excise duty for
the case of Latvia[5]).
Figure 8 and Figure 9 provide additional information on
the evolution of retail prices for residential consumers in the capitals of 15
Member States, based on the household energy price index (HEPI) from VaasaETT
and E-Control, the Austrian regulator[6].
The HEPI index breaks down the taxation
component further into energy and non-energy related and it provides up-to date
retail price data on a monthly frequency since January 2009.
Error! Reference source not found. describes the main drivers by component and by Member State and provides a description of the elements of the end consumer bill for
electricity and natural gas and for household and industrial consumers.
Figure 8. EU15 natural gas prices, residential
consumers, 2009 – 2012
Figure 9. 2009 – 2012 differences and percentage
changes by component, Eurocent/kWh
Turning now to industrial consumers,
it appears that retail gas prices appreciated on average by 4%, from 4.44 Eurocent/kWh in 2008 to 4.62 Eurocent/kWh in 2012. This is the
smallest increase across the energy products (gas and electricity) and consumer
types (households and industrial consumers) that are analysed in this report.
And yet this seemingly reassuring picture
results from a variety of different combinations of ups and downs in components
that are specific for each Member State, as illustrated by Figure 10 and Figure 11. 
In 2012 the energy element was spread in a
range between 2 Eurocent/kWh and 5 Eurocent/kWh. As for household consumers,
Romania and Luxembourg were again to be found respectively at the cheap and
expensive ends. The energy accounted for 38% of the consumer price in Sweden
(lowest value) to more than 80% in Belgium, UK and Luxembourg (highest value). 
Network costs ranged between
0.19 Eurocent/kWh in the Netherlands and more than 1 Eurocent/kWh in
Finland and Sweden. These costs accounted from 4% (Hungary) to 22% ( Spain) of
the total price. 
Figure 10 Natural gas prices by component, industrial consumers, Eurocent/kWh
(2012)
Note: No data was reported for: Austria (2008), Cyprus
(2008 and 2012), Greece (2008 and 2012), Italy (2008 and 2012), Luxembourg
(2008), Malta (2008 and 2012) and UK (2008). Ireland reported only tax-related
elements.
As it was not possible to separate and take
out the recoverable taxes and levies from the taxation part, Figure 10 and Figure 11 report on all taxes and levies and
exclude possible exemptions. As such they should be seen as an upper limit. The
tax-related elements accounted for less than 5% in the UK, Belgium and
Luxembourg whereas in Austria, Finland and Sweden they represented more than a
third of the price. The combined level of elements ranged from 0.06
Eurocents/kWh in Luxembourg to 3.83 Eurocents/kWh in Sweden, the majority of
Member States being situated within a range of 0.5 Eurocents/kWh – 1.5
Eurocents/kWh.
Figure 11
Natural gas prices, industrial consumers, relative share of components
Note: No data was reported for: Austria (2008), Cyprus
(2008 and 2012), Greece (2008 and 2012), Italy (2008 and 2012), Malta (2008 and
2012) and UK (2008). Ireland reported only tax-related elements. * Luxembourg
data is for 2009.
From 2008 to 2012 the industrial consumers
in Belgium, the Czech Republic, Hungary, and Slovakia experienced a price
decrease of more than 10% in the energy component of their gas price. In France
and Sweden the decline was higher than 25%. On the other extreme, industrial
consumers in countries like Bulgaria and Luxembourg had to pay between 50% -
75% more in 2012 than what they paid back in 2008. In Croatia this increase was
almost 150%, mostly linked to the shipping rate of gas delivered at the border.
The costs related to network elements in
Hungary went down by 47% and Belgium, the Czech Republic, Croatia, Luxembourg,
Poland, Portugal and Romania also registering decreases. On the other side, the
French network tariffs increased 2.5 times as transmission and distribution
charges rose from 0.09 Eurocent/kWh in 2008 to 0.27
Eurocent/kWh in 2012 and as the storage component went from 0.04 Eurocent/kWh
to 0.18 Eurocent/kWh during the same period.
Figure 12 Natural gas prices, industrial
consumers, 2008 – 2012 percentage change by component
Finally, the taxation component decreased
marginally in the Czech Republic, Germany and the UK whereas notable increases
above 100% were observed in Belgium (increase in public levies and VAT and
energy contribution), Finland (increase in the excise tax – energy content and CO2
) and Croatia (increase in VAT rates). In Portugal the tax component increased
by almost 500 % (increase in VAT rate). 

1.2.1.1.                  
Costs related to energy and supply

In the second half of 2012 the energy and
supply component of household natural gas prices ranged from 1.5 cents/kWh
(RO) and 4.9 cents/kWh (LU). In the case of industrial users the ranges
were between 2 cents/kWh (RO) and 5 cents/kWh (LU). As natural gas
prices still heavily depend on oil-indexed long term gas import contracts, and
as indigenous gas production is constantly decreasing in Europe, higher oil
prices result in higher import gas prices, especially in the Central and
Eastern European countries where oil-indexation is dominant.
The 2012 annual survey on wholesale price
mechanisms by the International Gas Union shows that 44% of gas consumption in
Europe was priced on a gas-on-gas competition basis, as opposed to 51% of
gas consumption which was still oil-indexed. The share of gas-on-gas priced
volumes has increased by a factor of 3 since 2005 and by more than 7% over the
period 2010-2012. In contrast, oil-indexed consumption has gone down from
representing almost 80% of consumption in 2005 to 51% in 2012. Strong regional
differences persist in price formation mechanisms with about 70% of gas in
North-West Europe (defined in the survey as UK, Ireland, France, Belgium,
Netherlands, Germany, Denmark) priced on a gas-on-gas basis in 2012, compared
to less than 40% in Central Europe (Austria, Czech Republic , Hungary, Poland,
Slovakia and Switzerland).
Figure 13. Selected European benchmarks, wholesale
natural gas
Source: Platts
and BAFA
Figure 13 shows a
selection of different wholesale price contracts for natural gas in the EU. The
benchmarks presented represent a pure gas-on-gas competition benchmark set at
EU's largest and most liquid hub (National Balancing Point, NBP in the UK), a
theoretical pure oil-indexed price for gas (Platts Gas Contract Indicator, GCI)
and the price of actual gas imports at the German border, as published by the
German customs agency.  This selection of benchmark is expected to capture the
range of lowest wholesale price for gas in Europe (typically the NBP) to
highest (the theoretical pure oil-indexed price). Estimates of the Commission
show that a number of Member States in Eastern Europe pay border prices that
are somewhere in-between the German border price and the pure oil-indexed price
for gas.  
These wholesale gas market benchmarks show
similar trends over time. The peak of 2008 was followed by a collapse in 2009.
Between 2010 and the first half of 2013 gas prices on NBP and the German border
price have recovered to 2008 peak levels, while the pure oil-indexed price has
well exceeded 2008 levels. While the German border price has traditionally been
taken as an indicator showing the price of oil-linked gas into Europe, in the
past few years the German border price has increasingly been dropping away from
the Platts NWE GCI oil-indexed price indicator and converging towards the spot
gas price, especially since the second half of 2012.
Even within the EU, the gap between the
lowest and the highest wholesale gas price remains significant, as illustrated
in Map 3. Member States with a
diverse portfolio of gas suppliers and supply routes and with well-developed
gas markets reap the benefit by paying less for imports and generally having
lower prices.  In 2012 the difference between the highest and lowest estimated
wholesale prices in the EU stayed at around 18 Euro/MWh[7].
Based on the latest report from Prospex
Research[8], the total traded volumes (including exchange spot and forward and
OTC cleared and non-cleared) of the EU markets of natural gas stood at 32 200
TWh in 2011, a fifth consecutive year of strong growth. This number compares to
a gross inland consumption in the EU of 4 600 TWh. The gas traded volumes are
also approximately 4 times bigger than those recorded for electricity.
The UK market is by far the most liquid,
recording trading volumes higher than 20 000 TWh. Market operators on the Dutch
and German markets exchanged respectively 6 500 TWh and 2 100 TWh. The highest
churn factors[9] were in the UK (23.6) and the Netherlands (16.3), followed by
Austria (4.4), Belgium (4.2) and Germany (2.5). OTC accounts for more
than 80% of the traded volumes. Similar to electricity markets, the cleared OTC
has a much smaller share than the non-cleared OTC under which the gas volumes
from the long term contracts are recorded. 
Map 3 Wholesale prices for gas in the EU
Textbox 1 Competitive
Pricing Brings Norwegian Gas Exports to the EU close to Russian Exports
 Against the background of weaker demand in the course of 2012 exports of natural gas from Norway to the EU have risen to levels comparable with Russian natural gas exports.   Data on imports of natural gas from the Russian Federation and Norway is sometimes difficult to reconcile. Eurostat’s database on international trade Comext contains no or patchy data on the gas import volumes from the Russian Federation and Norway for some big EU importers, such as Germany and France.   IEA statistics show that in 2011 Norway exported a total of 99 bcm. The Norwegian Petroleum Directorate production figures show that in 2012 Norway produced 114.8 bcm oil equivalent gas for sale: a 15% increase in natural gas exports on an annual basis. Of that amount, 107.6 bcm was exported to the EU, according to Gassco, the Norwegian TSO. Another source of information is the Gas Trade Flow platform of the IEA, according to which 105.8 bcm of Norwegian gas entered into Germany, France, the UK and Belgium between January and November 2012.   At the same time, the volumes of Russian gas entering the EU fell by approximately 8%. According to the 2011 annual report of Gazprom, in 2011 the company exported 150 bcm to European customers, out of which 26 bcm to Turkey. A breakdown of exports by country shows that the 2011 sales to the EU amount to 122 bcm5; in addition, in 2011 Gazprom exported 5.25 bcm to the three Baltic states. Gazprom’s CEO Alexey Miller was quoted by ICIS-Heren European Gas Markets as saying that in 2012 Gazprom’s exports of natural gas to Europe were equal to 138 bcm.     Norwegian companies have been actively changing their pricing policy. Torgrim Reitan, CFO of the Norwegian producer Statoil that controls 75% of Norwegian exports, was quoted by ICIS-Heren in October 2012 as saying that the company has concluded the renegotiation of some half of its contracts. New Statoil contracts are also being negotiated purely on a spot indexation basis, such as the November 2012 ten year deal with German firm Wintershall - the natural gas unit of chemicals firm BASF – which is spot-indexed mainly to the NCG and GASPOOL hubs. The contract is for a total of 45bcm, equal to more than 6% of Germany’s annual gas consumption. These developments are pointing to a fundamental change in the way traditional natural gas exporters to Europe are pricing their product.   In addition, in January 2013 Norway’s Ministry of Petroleum and Energy submitted a proposal to reduce the tariffs for trans­port and treatment of new gas volumes from the Norwegian shelf. This will reduce the cost of extraction companies in Norway, possibly facilitating more exploration, development of more discoveries and further measures on existing fields. Bloomberg have reported that the cuts could be by as much as 90% on the original fees.   In Russia, changes appear to have been less radical. In its 2011 annual report, Gazprom maintains that the oil price link is indispensable for long-term business planning. At the same time, as reported by Reuters, Gazprom has offered a number of discounts in its long-term prices in 2011 and 2012 to a number of companies. In its 2011 annual report Gazprom announced agreements to adjust pricing conditions with Italy’s Edison and Sinergie Italiane, France’s GDF SUEZ, Germany’s WIEH and Win¬gas, and Slovakia’s SPP. In 2012, agreements on contract price revision were signed with Austria’s EconGas, Centrex and GWH Gashandel, Italy’s Eni, Germany’s E.ON Ruhrgas, Netherlands’ GasTerra, and Poland’s PGNIG. In accordance with these agreements, contract price formulas with oil indexation were adjusted.   Furthermore, Gazprom’s officials were quoted by Reuters as saying that the company had set aside 4.4 billion USD for 2012 refunds and eventually paid out 2.7 billion USD. Reuters further quotes Gazprom officials as expecting to refund 4.7 billion USD in 2013.   The recent developments show that for the moment Norwegian producers are adapting faster to the new gas market conditions than other exporters. By changing the price setting mechanism to gas-on-gas they have been able to retain consumers and indeed increase their market share to the detriment of other exporters such as the Russian Federation and Algeria. At the same time, recent announcements on refunds following agreements on contract price revision seem to suggest that Gazprom is offering price discounts on its existing contracts without fundamentally changing the pricing mechanism.   Yet, with gas exports hitting record levels, Norway is approaching full utilisation of its pipelines (transport capacity of the Norwegian pipeline system is 120 billion Sm3 per year). Further export growth of Norway may thus depend on transport capacity, including LNG terminals, and fields coming online. 
According to some sources, recoverable
shale gas in the EU could range between 2.3 tcm and 17 tcm[10], these estimates
should however be seen in the context of the total proved natural gas reserves
that for the EU were about 4 tcm in 2011[11].
Textbox 2 Potentials and uncertainties for
shale gas exploration in the EU and the US[12]
 Information on EU shale gas reservoirs is limited and uncertain, due to early stages of exploration. It appears nonetheless that potential shale gas producers in the EU may not be able to achieve similar production volumes and costs as their US counterparts. The main reason would be that Europe's shale gas reserves appear to be significantly smaller than the US ones. In addition, they would also be less concentrated: between one third and half of the potential US reserves are located in one basin while other US basins are also sizeable (Haynesville, 10% of total, around 2 tcm); on the other hand, the EU potential reserves are dispersed across several countries, this may entail lower economies of scale in their exploitation, compared to the US. 
Linking
wholesale and retail markets: natural gas 
The supply and demand of natural gas
possess distinctive features that set it apart from other network industries
such as electricity generation. Whereas the practise of administered,
non-market prices still comes out as a suboptimal policy choice, those features
ensure that the inefficiencies incurred are perhaps on a smaller scale than
those for electricity.
Apart from chemical processing in the
upstream, the characteristics of natural gas remain virtually unchanged from
the extraction well to the delivery point as an end product. This contrasts
strongly with the significant transformation of the input fuel that is turned
into electricity. The production process for natural gas is much more
homogenous, as extraction and delivery systems appear quite similar when
compared to the variety of electricity generation technologies. As a result,
the price of the end product is more closely linked to the input commodity than
for electricity.
On the demand side, it is in general easier
to find substitutes for the uses of natural gas than for those of electricity[13].
On the supply side, unlike electricity,
only few Member States can rely on indigenous production of natural gas. As the
European conventional resources are gradually being depleted, the relative share
of natural gas delivered from external sources in gross inland consumption is
projected to grow. 
Historically, most Member States signed
long term contracts with suppliers outside of the EU and those suppliers
shipped and delivered the commodity at the border via a pipeline or with a
fleet of LNG vessels. The contract price of gas was determined by its
replacement value in the end-use sectors. Gas prices were indexed to the prices
of energies competing with gas in final energy consumption – most often heating
oil or diesel.
As a result from all of the above, the
scope of price regulation seems to be more limited than for electricity. For
example, few Member States can set end consumer prices below production costs
because very few can produce natural gas in the first place. Setting prices at
levels that would accumulate tariff deficits in the balance sheet of national
companies does not seem to be an appealing option either: it can affect the
bargaining power of those companies when they negotiate new terms with external
suppliers. 
Thus, the shortcomings of price regulation
of natural gas are more subtle. Yet, such practises are slowing down the
functioning of the internal energy market. Next to the clustering effect[14] which is similar to the one observed in electricity, fixing end-consumer
prices extends the application of gas indexation. 
The next charts illustrate that as the EU
wholesale markets are maturing, more and more gas is being delivered under
gas-on-gas pricing mechanisms. Administered prices that reflect oil indexation
only would then delink the retail level from the true fundamentals of supply
and demand on the EU gas market, as defined by the market conditions on the
hubs.
Figure 14 Wholesale gas price formation mechanisms
in Europe
Source: International Gas Union
The rise of traded
volumes in the European hubs, as shown in 
Figure 14 and Figure 15 is also due to the fact that hub prices
have been significantly lower than oil indexed prices throughout 2008 – 2012.
This point is further developed in Section 1.2.1.1. It is interesting to
observe that the lack of wholesale and network integration at the EU level is
proving to be very costly for consumers situated in isolated areas with
inexistent or very illiquid wholesale markets – which are the consumers that
cannot benefit from cheaper sources of gas. 
The latest market monitoring report from
ACER-CEER[15] estimates for example that household consumers from Hungary, Italy,
Romania, Latvia, Estonia, Greece, Poland, Finland, the Czech republic, Sweden,
Slovenia and Lithuania could save between 100 and 200 Euros of their annual
bill if the price for gas supplied at the border was comparable to the prices
on the liquid hubs in Western Europe, as shown in Figure 16. In Bulgaria, one of the poorest
Member States, consumers could save up to 250 Euros per year.
Figure 15. Traded volumes on European gas hubs

Barriers to the completion of the internal
market are further analysed in the ACER-CEER report. It indicates that, “in 2012, 46.2 million European household customers (about 46% of the
total number of households with natural gas) were supplied under regulated
prices (a 1.5% decrease compared with 2011)”.
Figure 16. Gross welfare loss per year, per typical household consumer, due
to lack of wholesale and network integration in EU27 – 2012 (Euro/year)
Map 4 Method of price regulation (natural gas)
and update frequency in months in Europe - 2012
Map 4, again from
the market monitoring report of ACER and CEER, illustrates that 15 Member
States continued to regulate prices in 2012. “At the end of 2012, Bulgaria,
Greece, Hungary, Latvia, Lithuania, Poland, Portugal, Romania, and Slovakia,
more than 90% of households under regulated prices. In Denmark, France, and
Italy between 70% and 90% of household consumers chose regulated prices. In
Ireland, the number of households with regulated prices dropped to a record low
(66%) in 2012, down from 98% three years before. In Spain and Belgium, fewer
than 35% of household customers were still on regulated prices in 2012.” 
The Consumer Markets Scoreboards[16] show that consumers
rank the gas market among the poorly functioning markets. In 2013, the market
ranks 22nd out of 31 services markets.  As
is the case with electricity, the gas market has particularly poor scores on
the choice of suppliers available in the market (lowest out of all services
markets) and comparability of offers (fifth lowest). In addition, only 3% of
consumers have switched products or services with their existing provider and 8%
switched supplier during the past 12 months (3rd lowest among the 14
'switching services' markets)[17].
According to Commission services' empirical
estimate on natural gas price drivers[18], the natural gas prices are largely driven by long term oil
indexation contracts. Among other price determinants that influence the formation
of retail natural gas prices, import dependency and diversification of imports
are important factors. In parallel, market opening and especially the option of
having access to hubs have a downward impact on retail prices by stimulating
the diversification of gas supplies, enhancing market's liquidity and by
promoting the most efficient allocation of gas supplies. Especially, market
opening eliminates the possibility of having artificially low regulated prices
and cross-subsidies between different consumer groups by promoting the cost
reflectiveness of tariffs which provide incentives to new entrants to enter the
supply market. 
This is important, as in the natural gas market similarly to the case of electricity market the distribution of costs through
regulated prices might be driven by political preferences, in favour of energy
intensive industries. Finally, unbundling of networks and
the population density put downward pressure on prices. The first driver
benefits the consumers by contributing to lowering the infrastructure cost,
especially under cases where a tight supervision of investment plans is exerted
by regulatory authorities and the latter factor by lowering the transmission and
distribution unit cost of investments. However, the downward effect of these
factors is limited, as they affect a small part of the retail tariff.

1.2.1.2.                  
Costs related to networks

In the second half of 2012 the network
component of household gas prices ranged between 4.9 cents/kWh (Spain) and
0.32 cents/kWh (Estonia). In the case of industrial gas prices the network
component ranged between 0.2 cents/kWh (the Netherlands) and
1.14 cents/kWh (Sweden).  
As with electricity network costs, the
proceeds collected from the network component of the end consumer bill are
intended to reflect pipeline costs related to operational expenditures,
depreciation and the cost of capital. 
Pipeline operating
costs vary mainly according to the number of compressor stations, which require
significant amounts of fuel, and local economic conditions. The expected load
factor determines the optimal mix of diameter and compression capacity. The
pipeline diameter can be linked to the pressure level and to the type of
transportation: transmission (mostly pipelines with high and median diameter
and high pressure levels) or distribution (mostly pipelines with small
diameters and low pressure levels).
As in the case of electricity network
costs, direct comparison of unit tariffs should be done with caution due to
differences between countries in areas such as quality of service, market
arrangements, main technical characteristics, topological and environmental
aspects of the networks, e.g. consumption density, generation location, that
influence the level of such charges. 
Detailed and harmonized information on gas
networks in the EU is in general scarce with no scarce data on total length and
age of operation by component. The Framework Guidelines on rules regarding
harmonised transmission tariff structures for gas apply to the transmission
services offered at all entry and exit points of gas TSOs, irrespective of
whether they are physical or virtual[19]. 
Figure 17 Length and relative share of Member States
gas grids by pipeline diameter
   || < 10” (km) || 10”–24” (km) || > 24” (km) || Total (km) 
 AUSTRIA || 4243 || 1398 || 1522 || 7163 
 BELGIUM || 1912 || 479 || 1227 || 3618 
 BULGARIA || 431 || 415 || 1758 || 2603 
 CROATIA || 0 || 695 || 70 || 765 
 CZECH REPUBLIC || 35 || 569 || 2753 || 3357 
 DENMARK || 1078 || 324 || 1440 || 2841 
 ESTONIA || 326 || 436 || 0 || 761 
 FINLAND || 606 || 0 || 257 || 863 
 FRANCE || 26799 || 476 || 6313 || 33588 
 GERMANY || 34603 || 18187 || 14337 || 67127 
 GREECE || 207 || 82 || 741 || 1029 
 HUNGARY || 1021 || 2253 || 1925 || 5199 
 IRELAND || 526 || 524 || 1057 || 2106 
 ITALY || 10529 || 9039 || 9055 || 28623 
 LATVIA || 403 || 184 || 520 || 1108 
 LITHUANIA || 998 || 148 || 660 || 1806 
 LUXEMBOURG || 41 || 239 || 0 || 280 
 NETHERLANDS || 4063 || 1208 || 3144 || 8415 
 POLAND || 5801 || 8668 || 1149 || 15618 
 PORTUGAL || 168 || 225 || 738 || 1130 
 ROMANIA || 1154 || 2405 || 1570 || 5129 
 SLOVAKIA || 762 || 2888 || 1970 || 5621 
 SLOVENIA || 752 || 6 || 0 || 758 
 SPAIN || 908 || 4573 || 6627 || 12108 
 SWEDEN || 965 || 0 || 20 || 985 
 UNITED KINGDOM || 1637 || 3421 || 12771 || 17828 
Note. The pipeline diameter can be linked to the
pressure level and to the type of transportation: transmission (mostly
pipelines with high and median diameter and high pressure levels) or
distribution (mostly pipelines with small diameters and low pressure levels)

1.2.1.3.                  
Costs related to taxation

In 2012 median EU households paid between
0.28 Eurocent/kWh (UK) and 5.66 Eurocent/kWh (SE) for the taxation
component. In the case of industrial consumers, taxation accounted for between
0.06 Eurocents/kWh (LU) and 3.83 Eurocent/kWh (SE). The Energy Tax
Directive sets minimum levels of excise duty for natural gas used for heating
at €0.15 per gigajoule for business use  and €0.3 per gigajoule for
non-business use. 
Tax Rates - VAT and excise duties
As with electricity (see section 1.1.1.3),
VAT rates on natural gas are broadly constant across Member States. Luxembourg
and Greece charge reduced VAT rates of 6% and 13%, respectively, on natural gas
consumption for heating (business and non-business use), as well as propellant
use. Ireland charges a reduced VAT rate of 13.5% on natural gas for
industrial/commercial use, as well as heating use (business and non-business
use), while the UK, Italy and the Netherlands charge reduced rates of 5%, 10%
and 19%, respectively, on natural gas for non-business heating use. VAT rate on
gas in Croatia, Sweden and Denmark is at 25% and in Hungary at 27%.
Figure 18. VAT rates on natural gas
Source:
European Commission 
Note: *Reduced VAT rates, see details in text.
The Energy Tax Directive sets minimum
levels of excise duty for natural gas used for heating at
0.15 Euro/GJ in the case of business use (0.5 Euro/MWh)[20] and at 0.3 Euro/GJ (1 Euro/MWh) for non-business use and
for industrial/commercial use. 
Table 1. Excise duties levied on natural
gas, Euro/MWh, 2013
 Natural gas, EUR/MWh (1) || Industry commercial use || Heating business use || Heating – non-business use 
 Belgium (2) || 0,47 || 0,47 || 0,97 
 Bulgaria || 1,55 || 0,18 || 0,18 
 Croatia || 1,98 || 1,98 || 3,92 
 Czech Republic || 1,22 || 1,22 || 1,22 
 Denmark || 39,50 || 33,71 || 33,71 
 Germany || 13,88 || 4,10 || 5,50 
 Estonia || 0,00 || 2,52 || 2,52 
 Greece || 5,40 || 5,40 || 5,40 
 Spain || 4,14 || 0,00 || 0,00 
 France || 1,19 || 1,19 || 0,00 
 Ireland || 4,10 || 4,10 || 4,10 
 Italy || 1,15 || 1,22 || 4,28 
 Cyprus || 9,35 || 9,35 || 9,35 
 Latvia || 1,65 || 1,65 || 1,65 
 Lithuania || 0,00 || 0,00 || 0,00 
 Luxembourg || 0,00 || 0,54 || 1,08 
 Hungary || 1,12 || 1,12 || 1,12 
 Malta || 9,35 || 3,02 || 3,02 
 Netherlands || 19,03 || 19,03 || 19,03 
 Austria || 5,97 || 5,97 || 5,97 
 Poland || 0,00 || 0,00 || 0,00 
 Portugal || 1,08 || 1,08 || 1,08 
 Romania || 9,35 || 0,61 || 1,15 
 Slovenia || 4,42 || 4,42 || 4,42 
 Slovakia || 9,35 || 1,33 || 1,33 
 Finland || 10,47 || 10,47 || 10,47 
 Sweden || 10,25 || 10,25 || 34,17 
 UK || 0,00 || 0,00 || 0,00 
Source: European Commission Excise
Duty Tables[21]. 
Notes: (1) Some Member
States impose other charges and levies that form part of the price of natural
gas paid by the final consumer, including environmental taxes, natural gas
taxes, concession fees, CO2 and energy taxes, strategic stockpile fees, grid
charges (in addition to transmission and distribution).; (2) In Belgium, a
federal contribution of EUR 0.468/GJ is applied; 
The levels of excise duty which Member
States charge in addition to the minimum rates set by the Directive vary
significantly by country and are frequently applied unevenly across sectors.
For example, in Bulgaria, Denmark, Germany, Malta, Romania and Slovakia,
natural gas for industrial and commercial use is subject to higher excise
duties than natural gas used for heating.
Tax exemptions
As indicated in the discussion on the role
of taxation on electricity prices (section 1.1.1.3), tax exemptions may be
available in some countries to specific sectors. 
In eleven EU countries natural gas for
heating use by businesses pays zero or lower excise duty than heating use by
non-businesses. Seven EU countries levy zero excise duty on gas used for
industrial and commercial purposes; out of these seven four levy zero excise
duty on gas used for heating by businesses.
Most of the Member States applying a total
tax exemption for natural gas used for heating base it on Article 15(1) (g) of the Energy Taxation Directive, which
allowed this exemption/reduction for the maximum period of 10 years; this
possibility expired in the end of 2013.  Member States using this option need
to comply with EU minimum as from 1 January 2014. The other possibility for tax
exemptions is for energy intensive business; however every measure has to
comply with the state aid rules.
In the United Kingdom, the Climate
Change Levy is a tax imposed on consumption by business and the public sector
of electricity, natural gas and other fuel sources, but energy intensive
industries qualify for a reduction of 80% on this levy, on condition of meeting
certain energy-saving targets set out in a Climate Change Agreement (see
details in section 1.1.1.3). 
In Denmark, under the Green Tax
Package scheme, EIIs are completely exempt from energy taxes, and almost
completely exempt from carbon taxes.[22]
Processes which participate in Voluntary Agreements, committing them to energy
efficiency improvements, are eligible for a rebate of 100% on their energy tax
and 97% on their carbon tax.
In the Netherlands, taxes on natural
gas and electricity consumption are based on a bracket system, which sets
marginal rates based on the amount of use. The rates decrease with increased
use, and different rate schedules apply for industrial, residential and
agricultural use. 
In Belgium, EIIs with an
environmental agreement are entitled to a 100% exemption on the excise tax on
fuels they use, as well as on electricity consumption.[23]
In Finland, a special rate of EUR
0.244/MWh applies to consumers with consumption greater than 70,000 MWh per
year in the steel industry (out of the scope of the
Energy Taxation Directive).

1.2.2.     
Natural gas price developments in selected
industries

Based on the methodology described in Error! Reference source not found.,
the results of several case studies for selected energy-intensive industries
are presented below with regard to natural gas prices. All caveats on the
interpretation of the results for electricity prices reported by the sampled
plants apply in the case of gas prices too. As
in the case of electricity, this section starts with presenting and comparing
the variation of natural gas price data for each of the seven sectors assessed.
In particular, for each sector and the
related EU-wide sample (not split into regions) the average natural gas prices
paid by operators are presented together with standard deviation. The
consumption ranges are also presented using the median and box plots, the
former indicating the value which splits the sample in half; the latter
indicating the range of values between which 50% of the data sample lay.
Natural gas data is not available or used
for all sectors as, for example, both chlorine and aluminium producers mainly
rely on electricity as energy input. The number of questionnaires used for each
sector is reported below.
Table 2 Number of questionnaires used in cross-sectoral analysis
 (sub)sector || N. of questionnaires Natural gas 
 Bricks and roof tiles || 16 
 Wall and floor tiles || 20 
 Float glass || 10 
 Ammonia || 10 
 Chlorine || - 
 Steel || 13 
 Aluminium || - 
 Total || 69 
As in the case of electricity although with
lower observed gaps, larger consumers pay lower prices. The difference in the
price of natural gas paid by an average producer of bricks and an average
producer of ammonia is of 7.0 €/MWh. Gas prices in the sample of large users
discussed are mainly determined by the energy component and do therefore offer
less flexibility than electricity contracts for possible discounts or
exemptions.
Figure 19 Natural gas
consumption range and price variations grouped by sector (69 plants)
Source: CEPS, calculations based on questionnaires
Table 3 Average natural gas prices and median
consumption in various sectors (69 plants)
   || Bricks || Tiles || Steel || Glass || Ammonia 
 Average price (€/MWh) || 34.0 || 32.0 || 32.1 || 27.0 || 26.5 
 Median consumption  (GWh) || 44.3 || 142.5 || 288 || 406.2 || 4,446.3 
Source: CEPS, calculations based on questionnaires

1.2.2.1.                  
Bricks and roof tiles

The results of the case study for bricks
and roof tiles presented below are based on the answers provided by a sample of
13 plants. The share of the sampled plants in EU production is unknown.
Production volumes are reported using different units due to homogeneity of
products.
Table 4 Number of questionnaires used in the brick and
roof tiles case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison 
 23 || 13 || 13 || 13 || 8 || 6 
Data collected show that the average price
of natural gas paid by the 13 sampled producers of bricks and roof tiles has
increased by 30% between 2010 and 2012, from 30.4 to 39.5 €/MWh. The spread
between the lowest and the highest price has also increased, going from 29.4 to
38.8 €/MWh. Different geographical regions have
all seen an increasing trend although of different intensity, as can be seen
from the table below.
Table 5 Descriptive statistics for natural gas prices paid by the 13 sampled
EU producers of bricks and roof tiles (€/MWh)
 Natural Gas price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 30,4 || 33,2 || 39,5 || 29,9 
 EU minimum || 18,7 || 25,6 || 24,7 || 32,1 
 EU maximum || 48,1 || 57,2 || 63,5 || 32,0 
 Northern Europe (average) || 28,9 || 32,7 || 39,7 || 37,4 
 Central Europe (average) || 30,0 || 29,7 || 31,9 || 6,3 
 Southern Europe  (average) || 31,2 || 36,2 || 43,2 || 38,5 
Northern Europe includes 5 plants: IE, UK,
BE, LU, NL, DK, SE, NO, LT, LV, FI, EE
Central Europe includes 3 plants: DE, PL, CZ, SK, AT,
HU
Southern Europe includes 5 plants: FR, PT,
ES, IT, SI, HR, BG, RO, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires
On average, the 5 operators in Southern
Europe pay the highest price for natural gas. They already did in 2010, but
also faced a considerable increase in the period 2010-2012 (+38.5%), compared
to the moderate one observed in the 3 plants in Central Europe (+6.3%).
In terms of components, the energy
component is the major driver of natural gas prices in the 13 sampled plants.
Over the period examined and for the whole of the sample examined, it has
increased by 42%, from 26.4 to 37.5 €/MWh. Such evolution, accompanied by a
decreasing impact of the other components in absolute terms, has implied a
significant increase of the relative impact of the energy component on the
overall price, which has gone from 87% to 95%.
Figure 20 Components of the natural gas bills
paid by the 13 sampled bricks and roof tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
While an increase in the energy component
can be observed in all regions and in particular in Northern and Southern
Europe (5 plants in each of the two regions), Southern Europe was characterized
by an increase also in the other two components, that is grid fees and
non-recoverable taxes, which went up by 22% and by a factor of 9.5%,
respectively.
As a share of total price of natural gas,
grid fees in 2012 have the largest share in the 3 plants in Central Europe
(10%) followed by the 5 plants in Southern and the 5 plants in Northern Europe
(6% and 4%, respectively).
Figure 21 Components of the natural gas bills
paid by the 13 sampled bricks and roof tiles producers in Europe (%)
Source: CEPS, calculations based on questionnaires
As indicated in the description of the
methodology (Annex 2), case studies also looked at the issue of gas and/or
electricity intensity for the sampled plants. In particular, the most and the
least efficient plant of the sample - in terms of one or the other energy input
- are compared in terms of gas or electricity price.
In the case of bricks and roof tiles, the
efficiency gap between the most and least efficient plant (plant A and B,
respectively) has been reducing between 2010 and 2012, while the differential
in the gas price paid increased considerably. General conclusions cannot be
drawn but it seems clear that, under current conditions, potential efforts from
plant B to further reduce its gas intensity and get closer to best performers
in the sector would not allow addressing the clear competitive disadvantage
represented by far higher gas prices.
Figure 22 Natural gas intensity and natural
gas prices of two plants (indexed values)
Source: CEPS, calculations based on questionnaires.
Lowest value = 100.

1.2.2.2.                  
Wall and floor tiles

The results of the case study for wall and
floor tiles presented below are based on the answers provided by a sample of 12
plants to a questionnaire and to each sections of it, as reported in the table
below.
It is not possible to establish the share
of the sampled plants in EU production due to the homogeneity of products,
respondents reported production volumes using different
units or did not disclose production volumes. 
Table 6 Number of questionnaires used in the wall and
floor tiles case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and margins 
 24 || 12 || 12 || 12 || 6 || 6 || 9 
Data collected from the 12 sampled plants shows
that the average price of natural gas paid by the sampled producers of wall and
floor tiles has increased by 27% between 2010 and 2012, from 25.0 to 31.7
€/MWh.
The spread between the lowest and the
highest price paid by the 12 respondents in the sample has diminished, going
from 11.3 to 10.2 €/MWh although the price range that plants in the sample
faced moved upwards - in particular the lower prices paid by some operators
increased faster – associated to an increasing gap of prices paid by different
operators.
Different geographical regions have all
registered an increasing trend although of different intensity, as it can be
seen from the table below:
Table 7 Descriptive statistics for natural gas prices paid by 12 sampled EU
producers of wall and floor tiles (€/MWh)
 Natural Gas price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 25,0 || 26,2 || 31,7 || 26,8 
 EU minimum || 21,0 || 23,1 || 27,6 || 31,4 
 EU maximum || 32,3 || 35,3 || 37,8 || 17,0 
 Central and Northern Europe (average) || 25,7 || 23,8 || 28,7 || 11,7 
 South-Western Europe (average) || 25,6 || 29,7 || 34,7 || 35,5 
 South-Eastern Europe (average) || 23,0 || 25,0 || 31,4 || 36,5 
Central and Northern Europe includes 3
plants: IE, UK, BE, LU, NL, DK, DE, PL CZ, LV, LT, EE, SE, FI
South-Western Europe includes 5 plants: ES,
PT, FR
South-Eastern Europe includes 4 plants: IT,
SI, AT, HU, SK, HR, BU, RO, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires
On average, in 2012 the 5 operators in
South-Western Europe paid the highest price for natural gas, following an
increase of more than 35% since 2010. An even higher increase was registered
for the 4 operators in South-Eastern Europe (36.5%) which however were paying
the lowest price in 2010. 
The energy component is the major driver of
the natural gas price, representing on average about 90% of the total in 2012
(28.4 €/MWh compared to 22.1 €/MWh in 2010). An increase is observed also for
the other two components whose cumulated weight on total price remained
nevertheless stable.
Figure 23 Components of the natural gas bills
paid by the 12 sampled wall and floor tiles producers in Europe (€/MWh)
Source: CEPS, calculations based on questionnaires.
An increase in the energy component can be
observed in all regions assessed and in particular in South-Western and
South-Eastern Europe (39% and 37%, respectively as accounted for by  5 and 4
plants, respectively) which is clearly the main driver of the sustained
increase in the overall price for the two regions discussed above.
As indicated in the description of the
methodology adopted, case studies also looked at the issue of gas and/or
electricity intensity for the sampled plants. In particular, the most and the
least efficient plant of the sample - in terms of one or the other energy input
- are compared together with the gas or electricity price they pay.
Figure 24 Components of the natural gas bills
paid by the 12 sampled wall and floor tiles producers in Europe (%)
Source: CEPS, calculations based on questionnaires.
In the case of wall and floor tiles, the
efficiency gap between the most and least efficient plant in the sample of 12
plants (plant A and B, respectively) has slightly increased between 2010 and
2012, while the differential in the gas price paid decreased. As for the other
case studies, general conclusions cannot be drawn but the data suggests that,
under current conditions, increasing gas prices equally affect best and lest
performers in the sector and reduce the advantages associated to increased
energy efficiency.
Figure 25 Natural gas intensity and natural
gas prices of two plants producing wall and floor tiles (indexed values)
Source: CEPS, calculations based on questionnaires.
Lowest value = 100.

1.2.2.3.                  
Float glass

The results of the case study for float
glass presented below are based on the answers provided by a sample of plants
to a questionnaire and to each sections of it, as reported in the table below.  The
10 plants represent about 19% of European production. 
Table 8 Number of questionnaires used in the float
glass case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs || Margins 
 10 || 10 || 10 || 7 || 10 || 7 || 4 
Data collected shows that the average price
of natural gas paid by the 10 sampled producers of float glass has increased by
28% between 2010 and 2012, from 23.7 to 30.3 €/MWh. The spread between the
lowest and the highest price has also increased, going from 9 to 12 €/MWh,
reflecting increasing disparities between operators in the sample. 
Starting from very close levels in 2010,
different geographical regions have all registered an increasing trend, which
determined new relative positions in 2012. In particular, the increase was
particularly sustained in the 4 plants in Southern and Eastern Europe (40% and
37.4%, respectively).
Table 9 Descriptive statistics for natural gas prices paid by the 10 sampled
EU producers of float glass (€/MWh)
 Natural gas price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 23.7 || 27.3 || 30.3 || 27.8 
 EU minimum || 19.0 || 23.8 || 24.4 || 28.4 
 EU maximum || 27.6 || 31.6 || 36.5 || 32.2 
 Western Europe (average) || 23.6 || 27.3 || 28.7 || 21.6 
 Southern Europe (average) || 23.7 || 27.7 || 33.2 || 40.1 
 Eastern Europe (average) || 23.8 || 27.2 || 32.7 || 37.4 
Western Europe includes 6 plants: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes 2 plants: BG, RO,
CZ, HU, EE, LT, LV, SK, PL
Southern Europe includes 2 plants: IT, MT,
CY, PT, ES, EL, SI
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires
As with other sub-sectors assessed, the
energy component represents the major driver of natural gas prices of the 10
float glass producers, accounting for about 95%. Between 2010 and 2012 this component
has increased by 24%, from 23.3 to 28.9 €/MWh. Several
plants in the sample declared that the major price driver in their gas contract
was the rise in oil price as their natural gas prices are linked to the price
of oil. The major increase of the energy component is
observed for the 2 plants in Eastern Europe (38%). The impact of other
components, although still marginal in absolute terms, has also increased. In
particular grid fees have increased from 0.80 to 1.09 €/MWh, while other
non-recoverable taxes and levies have increased from 0.11 to 0.28 €/MWh. 
Figure 26 Components of the natural gas bills
paid by the 10 sampled float glass producers in Europe (€/MWh)
Note: The analysis of the natural gas bill
components was not possible for plants in Southern Europe.
Source: CEPS, calculations based on questionnaires.
Figure 27 Components of the natural gas bills
paid by the 10 sampled float glass producers in the EU (%)
Note: The analysis of the natural gas bill
components was not possible for plants in Southern Europe.
Source: CEPS, calculations based on questionnaires.
Case studies also looked at the issue of
gas and/or electricity intensity for the sampled plants. In particular, the
most and the least efficient plant of the sample - in terms of either
electricity or gas - are compared in terms of the gas or electricity price they
pay.
In the case of float glass, the efficiency
gap between the most and least efficient plant in the sample of 10 plants (plant
A and B, respectively) decreased between 2010 and 2012 and the same level of
efficiency could be observed at the end of the period. As for the other case
studies, general conclusions cannot be drawn but data suggests that, under
current conditions, increasing gas prices equally affect best and worst
performers in the sector and reduce the monetary advantages associated to
increased energy efficiency.
Figure 28 Natural gas intensity and natural
gas prices of two plants (indexed values)
Source: CEPS, calculations based on questionnaires.
Lowest value = 100.

1.2.2.4.                  
Ammonia 

The results of the case study for ammonia
producers are based on the answers provided by a sample of plants to a questionnaire
and to each section of it, as reported in the table below. The 10 sampled
plants represent in total about 26% of EU27 production. Considering that about
80% of the global ammonia production is used for the production of fertilisers,
the case study focused on ammonia plants that in the vast majority of cases are
integrated in large installations that subsequently produce fertilisers. The
sample includes 2 small, 4 medium and 4 large-sized plants, which represent a
total of about 27% of EU production capacity. The 10 plants are located in 10
different member states.
Table 10 Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs 
 10 || 10 || 10 || 10 || 10 || 7 
Considering that about 80% of the global
ammonia production is used for the production of fertilisers, the case study
focused on ammonia plants that in the vast majority of cases are integrated in
large installations that subsequently produce fertilisers. 
Natural gas is the predominant fuel used by
the 10 sampled plants, for which it accounts for about 90-94% of total energy
costs. Data collected show that the average price of natural gas paid by the
sampled producers of ammonia has increased by 41% between 2010 and 2012, from 22.2
to 31.2 €/MWh.
The gap of prices paid by sampled producers
has also increased. Sustained price increase can be observed in all the
geographical regions defined, in particular in Eastern and Southern Europe (49%
and 48%, respectively), with the latter one resulting to be the region with the
highest price in all three years assessed.
As regard the different price components,
the energy part constitutes the major part of the price, accounting for more
than 95% of the total price of the 10 sampled plants. Between 2010 and 2012,
the energy component increased on average for the whole sample by 42%, from
21.2 to 30.1 €/MWh, and even more for the operators in Eastern Europe (+54%). The
share of other components in the total price for the 10 sampled plants is
relatively limited and as in the case of grid fees even decreasing (from 4% to
2.4%).
Table 11 Descriptive statistics for natural gas prices paid by the 10 sampled
EU producers of ammonia (€/MWh)
 Natural gas price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU average || 22.2 || 28.5 || 31.2 || 40.5 
 Western-Northern Europe (average) || 22.4 || 28.4 || 29.8 || 33.0 
 Southern Europe (average) || 23.6 || 30.7 || 34.8 || 47.5 
 Eastern Europe (average) || 21.0 || 27.6 || 31.2 || 48.6 
Western-Northern Europe includes: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes: RO, CZ, HU, EE, LT,
LV, SK, PL
Southern Europe includes: IT, MT, CY, PT,
ES, EL, SI, BG
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons. The number of sampled plants per region cannot be
disclosed due to confidentiality.
Source: CEPS, calculations based on questionnaires.
The comparison between regions does not
reveal particular differences but for the fact that, as from 2011, the plants
in Southern Europe are the only ones that pay a RES levy, although this still represents
a very limited share of total price (around 1%).
Figure 29 Components of the natural gas bills
paid by the 10 sampled ammonia producers in the EU (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 30 Components of the natural gas bills
paid by the 10 sampled ammonia producers in the EU (%)
Source: CEPS, calculations based on questionnaires.
Case studies also looked at the issue of
gas and/or electricity intensity for the sampled plants. In particular, the
most and the least efficient plant of the sample of 10 plants - in terms of one
or the other energy input - are compared together with the gas or electricity
price they pay. In the case of ammonia, the comparison suggests no relation
between efficiency gains and price levels.
Figure 31 Natural gas intensity and natural
gas prices of two plants (indexed values)
Source: CEPS, calculations based on questionnaires.
Lowest value = 100.

1.2.2.5.                  
Steel

The results of the case study for steel
producers are based on the answers provided by a sample of 17 plants, out of
more than 500 steel plants in the EU. The sample
installations were self-selected by the industrial sector.
Table 12 Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and Margins 
 17 || 17 || 15 (gas) 17 (electr.) || 14 (gas) 17 (electr.) || 11 (gas) 14 (electr.) || 3 || * 
* Data available from the steel cumulative cost
assessment study[24]

For each technology[25], sampled plants had
different capacity in order to reflect a distribution similar to that of the
steel making universe. 
Most steel makers are large gas consumers.
Large BOF integrated plants producing flat products included in the sample,
i.e. the vast majority of European BOF plants, consume between 1 and 1.5 mln
MWh of natural gas per year, most of it in the rolling facilities. EAF and
rolling facilities included in the sample consume between 450 and 700 thousands
MWh of natural gas per year.
The prices of natural gas paid by the 14 sampled
steel producers were on the rise throughout the entire observation period. Data
collected show that the average price of natural gas paid by these sampled
producers went up by 32% from 24.4 to 32.2 €/MWh between 2010 and 2012.
Different geographical regions have all registered an increasing trend although
of different intensity, as can be seen from the table below:
Table 13 Descriptive statistics for natural gas prices paid by 15 sampled EU
producers of steel  (€/MWh)
 Natural Gas price (€/MWh) || 2010 || 2011 || 2012 || % change 2010-2012 
 EU (average) || 24,4 || 27,8 || 32,2 || 32,0 
 EU (minimum) || 17,8 || 23,0 || 26,6 || 49,4 
 EU (maximum) || 35,4 || 47,9 || 59,1 || 66,9 
 Central and Eastern EU (average) || 27,6 || 26,1 || 31,3 || 13,4 
 Southern EU  (average) || 32,0 || 36,7 || 47,2 || 47,5 
 North-Western EU  (average) || 20,2 || 26,7 || 28,9 || 43,1 
 BOF Average || 24,4 || 26,2 || 30,8 || 26,2 
 EAF Average || 24,0 || 28,6 || 32,6 || 35,8 
North-Western Europe includes 9 plants: FR,
BE, LU, NL, IE, UK, DE, AT, DK, FI, SE
Central and Eastern Europe includes 3
plants: PL, SI, HU, RO, BG, CZ, SK, EE, LV, LT
Southern Europe includes 5 plants: IT, ES,
PT, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculations based on questionnaires.
In terms of components, the energy part is
the major driver of natural gas prices for the 14 sampled plants in Europe (one
respondent provided data on price trends, but not on components). Over the
period examined, for the sampled plants it has increased by about 28%, from
22.5 €/MWh, to 28.9 €/MWh. The share of energy in the total price paid by the
sampled plants in 2012 was down to 89%, compared to 92% in 2010, while other
components increased. The strongest increase was observed in other
non-recoverable taxes, which increased by a factor of 2.3 (from 0.3 to 1.0
€/MWh), although their weight in total price remained relatively limited
(around 3%), also in comparison to network costs which represent about 8%.
Figure 32 Components of the natural gas bills
paid by 14 steel producers in the EU (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 33 Components of the natural gas bills
paid by 14 steel producers in the EU (%)
Source: CEPS, calculations based on questionnaires.

1.3.           
Chapter conclusions 
 The retail segment is an essential
     element of the internal energy market (IEM) and ensuring conditions for
     fair competition and transparent price mechanisms on that segment is a
     necessary step in completing the IEM. 
 The progress on achieving a
     functioning retail market for electricity and natural gas in the EU has
     so far been difficult. Persistent divergences across Member States
     remain with few indications that prices may align in the near future.
 Strong factors are slowing down the
     completion of the retail IEM: the relative
     share of non-market elements in the end consumer bill is growing; the
     majority of final consumers are still under the non-competitive offer of
     the incumbents; the perceived complexity of bills and pricing schemes
     dampens demand response; too many Member States still practice regulated
     prices over large group of consumers which in turn brings such undesirable
     effects as cross subsidization, the accumulation of tariff deficits and
     creating barriers to entry as the regulated benchmarks acts as an anchor
     to competitive commercial offers. Coordinated EU action may prove to be
     the most efficient tool to mitigate those factors.
 The end consumer bill can be
     schematically broken down by 3 sub aggregates: energy, network and
     taxation. In the case of electricity, the energy element
     followed broadly developments on the wholesale markets, although the
     recent wholesale price decreases have only partly translated into retail
     prices. It remained stable on average, registering a 3% decrease for the
     median industrial consumer and a 7% increase for the households. It turns
     out that the element that can be directly linked to the operation of the
     IEM was the one that was least affected by price increases.
     However, its relative share in the final energy bill decreased from 46% to
     42% for the domestic consumers in the last 5 years[26].
 Costs related to the network component
     increased by 18% - 30% for consumers. Grid maintenance and development
     were among the driving factors for the transmission-related costs. The
     work of ENTSO-E, especially the TYNDP, has done much to improve the
     understanding on the different elements and the comparability of different
     costs across Member States. Yet, the transmission-related costs are only a
     minor part of the network component as the greater share of that element
     goes to cover expenses on the distribution grid. There is room for
     improving the cooperation of DSOs in Europe much in line to what has
     been done on the TSO level; as a minimum the visibility of that price
     component should be improved, perhaps by applying harmonised accounting
     standards.
 The taxation and levy element was
     a strong driver both for industrial and household consumers: in 5 years
     (2008 – 2012) it grew by more than 120% and 30% respectively. The energy taxation
     policy is a national competence, but a certain degree of harmonisation is
     provided through the EU energy tax directive. Yet, with regards to the
     energy- policy related instruments in forms of various charges and levies,
     especially those introduced to respect commitments to the 20-20-20 targets,
     there may be a case of sharing best practices and learning from the
     experience of other Member States. The design of these instruments and
     their optimal use should make sure that consumers are not overburdened
     beyond the targets.
 As
     a rule, prices of natural gas were more stable than those of
     electricity, registering modest increases in the range of 5-10% at the EU
     level from 2008 to 2012. Yet, the same dispersed picture of specific
     Member State cases emerges as for electricity, so in some cases it is
     difficult to generalise. Natural gas tends to be
     more expensive in the new Member States, especially when prices are
     measured in purchasing power standards. These countries can reduce the
     negative impacts of high gas prices on competitiveness and household
     expenditure by more grid integration, by the introduction of internal
     market rules and by establishing a more diversified portfolio of suppliers
     and routes.
 The energy and
     supply component of the retail price for natural gas remained stable.
     Between 2008 and 2012 on average for industrial consumers the energy
     component increased by less than 0.5% and for
     households increased by 4.6%. During the observed period its relative
     share declined from 70% to 68% (industrial consumers) and from 59% to 56%
     (household consumers). As in the case of electricity, the broad EU numbers
     conceal a wide range of variation for the retail gas prices across Member
     States and across types of consumers.
 Cost items related to the network
     component of the end consumer bill for natural gas increased by 10-15%
     from 2008 to 2012; as a result, its relative share increased by a
     percentage point from 11% to 12% (industrial consumers) and from 20% to
     21% (household consumers). Based on the available data, it was not
     possible to break down the costs on transmission and distribution and to
     estimate how much is attributable to maintenance and grid development.
     Transparency on these elements should be improved, as well as on the
     methodologies used by NRAs to estimate investment and operating costs and
     to define rates of return on this regulated activity. There is a room of
     improving the cooperation of DSOs in Europe, similar to what was done on
     the transmission level.
 Over the period 2008 – 2012 increases in
     the taxation component were in the range of 12-14%, significantly
     lower than the rates observed in electricity. The relative share of
     tax-related elements in the tax registered a marginal increase (from 18%
     to 20% for industrial consumers and from 22% to 23% for household
     consumers). 
 In addition to the analysis of
     statistical data on electricity and gas retail prices, in-depth analysis
     of price data at plant level in a selection of energy intensive
     industrial sectors through case studies indicated that electricity and gas
     prices were on the rise in the period 2010-2012. The
     general trend results from the combination of increasing prices, although
     at highly variable speed, registered in all regional samples, and in some cases
     widening price differentials could be observed between the regions.
 Network fees, taxes and levies, including
     support schemes for renewables were identified as drivers for the
     electricity prices in the surveyed plants whereas the energy component remained
     stable and on comparable level across regions. Gas prices were influenced
     by energy and supply costs which, based on the sector and regions
     assessed, varies between 80% and 97%. The registered increase in gas
     prices was mostly linked to increased commodity price and indexation of
     gas to oil price. With taxes, levies and network charges having a
     negligeable impact on the price dynamics.
 The case studies indicate that the
     dynamics of price increases varied across industrial sectors and across
     Member States of the EU (presented in this report as regions for
     confidentiality reasons) and that important differences remain in the
     price levels of electricity and gas paid by plants in the same industrial
     sector but located in different Member States. 
 These intra-EU
     electricity and gas price differentials indicate real locational
     advantages, but also suggest there may be a scope for improving
     procurement practices by industry, as well as for Member States to
     increase efforts in completing the internal market and in ensuring the
     cost effectiveness of policies financed through electricity and gas
     prices.   

[1] Median household consumer band D2 with annual consumption between
5.56 and 55.56 MWh per year. Prices measured in cents EUR / kWh.
[2] Second round effects in the interaction of retail electricity
prices and inflation (the electricity price being a component of the HICP) are
not discussed in this report.
[3] The data was gathered under a reporting exercise, in the spirit of
recital (16) and Annex II (n) of Directive 2008/92/EC. The data request
concerned the exact composition of the cost elements reported under energy and
supply, network and taxation components of retail prices of electricity and gas
for industrial and household consumers (median bands) in 2008 and in 2012. Data
for other years, consumer bands and components was not requested or reported.
[4] The outlier for Slovenia is due to the fact
that back in 2008 network and energy were bundled together; when both
components are taken together, the 2008 and 2012 prices appear stable.
[5] The national tax rate applied by Latvia is EUR 0.43 /GJ which is
close to the EU minimum of EUR 0.3 /GJ.
[6] http://www.energypriceindex.com/

[7] Estimated border prices and estimated LNG prices based on data from
Eurostat's database of international trade COMEXT. Day-ahead hub prices as
reported by Platts.  
[8] “European Gas Trading 2012”, Prospex Research, www.prospex.co.uk 
[9] The churn facto is defined as the ratio of traded volume to
physical consumption. It informs about the liquidity of the market place and
the quality of the pricing signal that is discovered on that market.
[10] European Commission (2012), Unconventional
gas: potential energy market impacts in the European Union, JRC Scientific and
Policy Reports, p 29
[11] Further information on shale gas reserve estimates are available in
the Forthcoming publication, Energy Economic Development in Europe, DG ECFIN
[12]  ECFIN, Energy economic developments in Europe, forthcoming
publication
[13] Yet, the demand elasticity should not be overestimated: the
switching of heating sources for example entails significant upfront capital
costs for end consumers.
[14] The regulated price offer acts as an anchor; it discourages
pro-active consumer behaviour, it protects incumbents and sets implicit
barriers to entry.
[15] The report is available here: http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER%20Market%20Monitoring%20Report%202013.pdf
[16] http://ec.europa.eu/consumers/consumer_research/cms_en.htm

[17] Consumer Market Monitoring Survey 2013 commissioned by DG SANCO, to
be used in the forthcoming 10th Consumer Markets Scoreboard
[18] DG ECFIN. Energy Economic Development in Europe 
[19] See Draft Framework Guidelines on rules regarding harmonised
transmission tariff structures for gas  http://www.acer.europa.eu/Gas/Framework%20guidelines_and_network%20codes/Documents/outcome%20of%20BoR27-5%201_FG-GasTariffs_for_publication_clean.pdf

[20] Business use is defined in Article 11 of the Directive as "use
by a business entity … which independently carries out , in any place, the supply
of goods and services, whatever the purpose or results of such economic
activities".
[21] See details on exemptions from excise duties at http://ec.europa.eu/taxation_customs/resources/documents/taxation/excise_duties/energy_products/rates/excise_duties-part_ii_energy_products_en.pdf
[22] ICF report, p142
[23] OECD p67
[24] http://ec.europa.eu/enterprise/sectors/metals-minerals/files/steel-cum-cost-imp_en.pdf

[25] See technology explanations, abbreviations
and representation in the sample in section Error! Reference source not found..
[26] The figures for industrial consumers were 67% and 55% respectively.

3.   Energy prices in a global context 

This chapter discusses the role of energy
in cost competitiveness from a global perspective. It provides analysis of
recent developments in global oil and coal markets as well as regional
developments in the wholesale prices of electricity and gas in some of the EU's
major economic partners. The chapter looks into retail price levels of
electricity and gas and their evolution over time, providing estimates of the
breakdown of electricity and gas prices and indications of energy price
subsidies in some major economies. 
In the case of electricity and natural gas,
price differences in regional prices across regions have always existed, but
the last few years have seen widening price gaps, in particular the price of
natural gas in the US, Europe and Asia. This process has been driven by factors
such as the shale gas boom in the US, the impact of oil-indexation on gas price
dynamics in the EU, and sharply increased gas demand in Japan in the aftermath of Fukushima.
It discusses the significance of energy
prices and costs for the competitiveness of different sectors of the economy,
looking into the role of the EU in global export markets for energy intensive
goods. 

3.1.           
Global energy commodity and wholesale prices 

Energy commodity prices vary across global
regions - the degree of variance partially depends on the existence of highly
liquid global markets and may reflect factors such as degree of competition,
production or import costs and contractual terms, cost of transportation, as
well as taxes and subsidies. 

3.1.1.     
Crude oil, coal and uranium

Crude oil is
the most commonly traded energy commodity with major price markets for the
world trade in crude oil moving largely in step (Figure 1). The presence of highly liquid
international markets and relatively low costs of transporting crude oil and
petroleum products explain the modest differences in prices across countries
and regions (Figure 106). The peak of crude oil prices in 2008 was followed by
a fall in 2009 and recover to levels exceeding 100 USD/bbl in early 2011.
Crude oil spot market prices have remained volatile since 2011 despite a recent
drop to the lowest level since July 2012. Spot prices for West Texas
Intermediate (WTI) and North Sea Brent crude oil benchmarks neared parity in
mid-2013. By contrast, the average Brent-WTI price spread in 2012 was about
19 USD/bbl and exceeded 20 USD/bbl in February 2013. Since spring 2013,
prices for these benchmarks have moved much closer together, as WTI increased
in relation to Brent as a result of new US crude oil transport infrastructure
and US refineries running at near-record levels.
Figure 1. Evolution of global crude oil prices
2007-2013
Source: IEA
2013. Note: North Sea on this graph is set by the lowest of the Brent, Forties,
Oseberg and Eko-fisk components. 
Average crude oil import prices are
affected by the quality of the crude oil that is imported into a country. For a
given country, the mix of crude oils imported each month affects the average
monthly price. Analysis of the IEA shows that over the first quarter of 2013
crude oil import costs increased over fourth quarter 2012 levels in all major
IEA member countries except the United States. Year on year, average import
costs in IEA member countries fell by 5.5%, with the United States (-9.2%) and
Korea (-5.6%) reporting the largest decreases.
Figure 2.
Evolution of average import costs of total crude imports
Source: IEA 2013. Energy Prices and Taxes,
2nd quarter 2013. 
Unlike oil, which is widely traded
internationally, the world coal market is predominantly supplied by
domestic production with internationally traded coal accounting for a
relatively small part of the market (around 20%). Internationally traded steam
coal is split into two major markets; the Atlantic basin (focussed on the
Amsterdam-Rotterdam-Antwerp, ARA hub) and the Pacific basin (focussed on the Newcastle hub). Europe is increasingly an import led coal market and international prices
act as leverage to negotiate price contracts with domestic coal producers. The
Atlantic market for steam coal is made up of the major utilities in Western
Europe and the utilities located near the US coast, with major suppliers being South Africa, Colombia, Russia and Poland; the share of US coal in total coal imports to the EU has
increased from 12% in 2008 to 17% in 2012 [1] [2]. The Richards Bay port in South Africa plays an important role in
constraining price divergence across the two basins.
Coal prices can differ due to differences
in coal quality and transportation costs. In recent years the spreads between
the major coal benchmarks for internationally traded coal to the Atlantic
market have been edging ever lower. China became a significant net importer of
coal in 2009, since when prices of Chinese coal imports have risen above those
in Europe and have remained at a price premium of up to 50% (see figure below).
Figure 3.
Evolution of coal price benchmarks 
Sources: Platts
and Bloomberg
The uranium
spot market typically exhibits low levels of liquidity and can deviate
significantly from the term market depending on the shorter term supply/demand
balance of market participants[3]. There is no formal exchange for uranium. The most liquid traded
form of uranium is U308 in the form of yellowcake (uranium concentrate
powder) for shipping to nuclear power stations. 
Figure 4.
Uranium prices 2009-2013
Source: Timera
Energy 2013 

3.1.2.     
Natural gas

The physical properties of gas make it more
expensive to transport than other energy commodities. Historically, as gas was
produced and consumed locally or regionally, international trade in gas was
quite limited. Therefore, in contrast with the relatively narrow price range of
other global energy commodities such as crude oil and coal, there are
pronounced inter-regional price differentials in natural gas traded
across the globe that have increased over recent years. The convergence or
divergence of prices differs in periods of tight supply or surplus relative to
demand; these are also determined by pricing mechanisms (gas-on-gas competition
or oil-indexation). Development of price signals, growth in the LNG spot market
and expansion of infrastructure may over time reduce global gas wholesale price
differentials. The growing LNG market is expected to also have an impact on
price convergence as is the liquidity and transparency of gas trading in
regional markets.
Analysis by the International Gas Union
points to different drivers of spot gas prices across different regions[4]. North America is a market where gas prices are driven by
demand and supply fundamentals and gas is traded at the liquid and transparent
Henry Hub. Current Henry Hub spot price levels reflect the impact of a surge in
shale gas production over the last 5 years. 
Northern Europe is also a market driven by liquid hub prices, primarily at the UK
NBP, Dutch TTF, the German NCG and Gaspool and the Belgium Zeebrugge. In 2012
about 70% of gas in North-West Europe[5]
was priced on a gas-on-gas basis. Yet, unlike North America, marginal price
dynamics at European hubs are influenced by oil-indexed pipeline contract
prices. 
Southern Europe seems increasingly influenced by the larger and more mature
Northern European market.  The Italian market has largely converged with
European hub prices and the relative isolation of the Iberian peninsula is
expected to decline with the development of new interconnection with France. In contrast, Eastern Europe has not yet developed a liquid gas trading hubs
and is yet to benefit from liquid markets where long-term contracted gas is
complemented by short-term and spot deals[6].
Asia is the
key driver of LNG market growth, with most gas delivered under long term
oil-indexed contract prices, typically at a substantial premium to US and
European hub prices. Even though South/Central America is a relatively
small gas market by volume, buyers in countries such as Argentina, Brazil and Mexico can have an impact on global spot pricing with spot price levels
typically trading within a band of Asian spot prices – and indeed at premium in
the second quarter of 2013.  
Figure 5
illustrates the continuing variation among global wholesale prices for natural
gas and indeed the volatility of prices in the period 2007-2013.The gap between
regional gas prices has started widening in 2010 and reached its highest level
in April 2012, when the day-ahead price on the National Balancing Point (NBP)
in the UK – the most liquid and traditionally lowest price gas hub in the EU –
was 4.2 times the price buyers paid at Henry Hub in the US; in the same month
the German border price was 5.8 times the price at Henry Hub. For comparison,
in 2010 spot prices at NBP were twice as high as these at Henry Hub and a year
earlier were at only 50% above those at Henry Hub.
Over the course of 2012, wholesale buyers
at the NBP (UK) paid over 3 times as much for gas as buyers at Henry Hub (US).
Over the course of 2012 the German border price was around 4 times greater than
the price paid by US wholesale buyers at Henry Hub. This trend is explained
mostly by the surge in US shale gas, which has driven prices down to historical
lows. At the same time, high oil prices have exerted upward pressure on gas
prices in Europe and Asia Pacific, which are mostly linked to oil[7].
The beginning of 2013 saw spot prices at
Henry Hub double from their historical lows of April 2012.  The decline in
international oil prices of early 2013 contributed to the stability or slight
reduction of gas prices outside of the US. 
Figure 5. Evolution of wholesale gas prices: US, UK, Germany and Japan (USD/mmbtu)
Sources:
Platts, Thomson Reuters, BAFA. For Japan: simple average price of LNG from Qatar, Malaysia, Indonesia and Nigeria  
Between 2007 and 2012 wholesale gas prices
in Europe and Asia Pacific – two regions where oil-indexation remains an
important pricing mechanism – rose, cementing their position as the two regions
with highest priced wholesale gas. 
Globally, analysis by the International Gas
Union shows that since 2007 wholesale gas prices have increased consistently in
all regions except North America. There have been wholesale gas price increases
in China and India, owing to greater import levels and increases in regulated
domestic prices. Latin America has also seen a doubling of wholesale gas prices
and in the former Soviet Union average prices have more than doubled, largely
due to the rise in regulated prices in Russia as they move towards the netback
value from Europe. In Africa, where over 85% of prices are effectively
subsidised, there have also been price increases and in the Middle East prices
have risen slowly, with a significant increase in 2012 over 2010 as a result of
regulatory changes in Iran (IGU 2013).
Figure 6.
Evolution of wholesale price levels by world region (2007-2012) 
Source:
International Gas Union and Nexant. Wholesale Gas Price Survey - 2013 Edition
Note:  Comparisons of wholesale price levels need to
be treated with caution. The wholesale price can cover different points in the
gas chain – wellhead price, border price, hub price, city-gate price – so the
comparison of price levels is not always a like for like comparison. Most of
the regions are defined along the usual geographic lines, although the IGU
includes Mexico in North America, and divides Asia in two: a region including
the Indian sub-continent plus China, called Asia, and another region including
the rest of Asia plus Australasia which is called Asia Pacific.
IGU's analysis also shows that the
combination of falling prices in North America and rising prices in Asia, Latin
America and the former Soviet Union, has led prices in the latter regions to
overtake those in the former. Only in the Middle East and Africa, where prices
are often restricted to the cost of production or below as a subsidy, are
average prices lower than in North America.
The widening of regional gas price
differentials has come against a backdrop of a number of important global
trends: from the surge in oil and gas production in the US due to exploitation
of shale gas[8] and other unconventional resources to opening up of new hydrocarbon
provinces in Africa and elsewhere and a shift in the energy balance towards
renewables in the EU (IEA, WEO 2013).
Figure 7.
Wholesale prices gas prices globally (USD/mmbtu, 2012)
Source:
International Gas Union and Nexant. Wholesale Gas Price Survey - 2013 Edition
Figure 8.
Average wholesale gas prices in 2012 (USD/mmbtu)
Source:
International Gas Union and Nexant. Wholesale Gas Price Survey - 2013 Edition
Note: In the definition of the International Gas
Union, gas wholesale prices can cover a wide range: from hub prices in fully
liberalised traded markets to border price in case of internationally traded
gas and to wellhead or city-gate prices in producer countries.
Looking at LNG price levels confirms once
again that Asia Pacific, along with some EU countries, remains at the high end
of LNG import prices. It also shows that Latin America is starting to pay
dearly to satisfy its increasing appetite for LNG supply, due to falling
indigenous production coupled with growing gas demand for electricity generation.
Traditionally LNG has been traded under long-term contracts, mostly indexed to
oil, with spot markets starting to emerge at the turn of the 21st
century and exceeding 30% of global LNG trade in 2012[9].
In 2012 LNG accounted for 19% of gas needs in Europe, as opposed to 46% in Asia
and 21% in Latin America[10], with Europe’s share of global LNG demand down against increased competition
from coal, availability of renewables and higher pipeline gas imports. 
Figure 9.
Overview of global spot gas prices for LNG in the first half of 2013
(USD/mmbtu)
Source: Thomson-Reuters
Waterborne 
From a competitiveness point of view,
future US LNG exports have been in the primary focus, in particular when
evaluating whether US LNG is cheap vis-à-vis alternative sources of supply such
as Australia and East Africa. From the perspective of potential importers, equally
if not more important is the fact that the structure of US supply contracts is fundamentally different to that of conventional LNG supply: US LNG
supply is hub indexed and inherently flexible. As a result, the possible
ramping up of US exports may have a significant impact on global LNG pricing
dynamics.
 SHALE GAS PRODUCTION IN THE US1 Shale gas production became significant in the US only from 2007/2008 onwards. In 2011 shale gas constituted more than one third of total natural gas production in the US – compared to only around 5% in 2005. The EIA estimates that in 2013 the US is set to overtake Russia and Saudi Arabia and become the world’s largest producer of petroleum and natural gas. Shale gas has revived otherwise declining natural gas production in the US and therefore its impact on the overall energy mix of the country should not be overstated.  The share of natural gas share in the US energy mix increased by only 2% between 2000 and 2011. A more significant increase could be observed in the electricity mix where the gas share went from 18% to 25%.A similar pattern can also be observed in the EU where the share of gas in the energy mix increased from 23% to 25% over the same period while it went from 17% to 24% in the electricity mix. The implications for energy dependence have been profound. Since the US has been able to source most of its increased natural gas consumption domestically, the country's overall import dependency has fallen to a record low of 18% in 2011, down from about 25% in 2000. In contrast the EU's total energy import dependency has increased from 47% to 54% in the same period (and from 49% to 67% in the case of natural gas). Natural Gas Production in the US and share of shale gas in total gas production Source: Energy Economic Development in Europe, DG ECFIN 

3.1.3.     
Electricity

Electricity is not a global commodity: the
need for proximity between electricity plants and customers makes it a regional
industry. Differences in energy mix and generation portfolios determine
regional variances between wholesale electricity prices. At the same time
markets in generation technology are global. Regional differences in wholesale
prices for electricity appear to be far less pronounced than in the case of
spot gas prices: over the second quarter of 2013 prices at the major wholesale
markets in Europe, the US and Australia all traded in the range
30-50 Euro/MWh.
The US has many regional wholesale
electricity markets. Wholesale electricity prices are closely tied to wholesale
natural gas prices in all but the centre of the country. EIA analysis shows
that average on-peak, day-ahead wholesale electricity prices rose in every
region of the US in first-half 2013 compared to first-half 2012[11]. The most important factor was the rise in the price of natural gas
in 2013 compared to 10-year lows in April 2012; spot natural gas prices at the major
hub in the US increased from 2.4 USD/mmbtu in the first half of 2012 to
3.7 USD/mmbtu in the first half of 2013. 
The increase in electricity prices was not
uniform across regional electricity markets in the US. Prices in the wholesale electricity
market of Texas increased less than much of the rest of the nation, largely
because of the mild weather this spring[12]. 
Analysis of the Australian Energy Regulator
shows that electricity spot prices fell steadily from 2010 until the
introduction of carbon pricing on 1 July 2012, with prices at the National
Electricity Market at or near record lows in 2011-2012. Following some initial
market volatility, the introduction of carbon pricing caused an uplift in
electricity spot prices of around 21%, in line with expectations[13]. The Australian Energy Market Commission states that nominal
wholesale prices rose nationally by 14%  from 2011-2012 to 2012-2013, in part
reflecting the impact of the carbon price[14]. In New South Wales wholesale energy prices rose by almost 30%
between 2012 and 2013. 
In Europe, falling coal prices since the
beginning of 2011, low carbon prices and the increasing share of renewables
have led to relatively stable electricity wholesale prices over 2012 and early
2013 and sharply decreasing prices in the second quarter of 2013 (see Error! Reference source not found.).
Regional wholesale electricity prices showed a higher degree of convergence
than in the last couple of years with the exception of the UK and Italy, two markets in which electricity usually trades at a premium in price to most
continental peers due to high dependence on natural gas and reliance on
imports. In the Central Western Europe (CWE) region, renewable electricity
generation in Germany and nuclear availability in France were important
determinants of wholesale electricity prices. A jump in the levels of renewable
generation helped to drive regional prices down in both the CWE and CEE regions
to four-year lows by the end of Q2 2013.
Figure 10. Electricity wholesale prices in Europe, US and Australia (2011-2013) 
Source: Platts,
Energy Information Administration, Australian Energy Market Operator 
Note: The PJM Interconnection’s Western Hub in the US stretches from southern Maryland north to Washington D.C. and northwest to central and western Pennsylvania. The PJM price is a weighted average between on-peak price (on-peak hours:
hour-ending 8 through 23) and off-peak hours (hour-ending 1 through 7 and 24);
this gives a good proxy of baseload price. ERCOT North is one of the five zones
operated by the Electric Reliability Council of Texas. The ERCOT North price is
weighted in the same manner as PJM West to give a proxy of baseload. The
Australian National Electricity Market (NEM) interconnects five regional market
jurisdictions (Queensland, New South Wales, Victoria, South Australia and Tasmania). West Australia and Northern Territory are not connected to the NEM. New South Wales is the largest among the five regional markets. All
electricity in the National Electricity Market (NEM) is traded via a gross pool
which is settled on a half hourly basis. Each jurisdiction or state settles
their own pool price, known as the Pool Price or Regional Reference Price
(RRP). 

3.2.       International comparison of retail prices of electricity and gas[15] 

This chapter compares the level of retail
prices for electricity and gas for medium-sized industrial consumers and
households in the EU with those in major global economies. Unless otherwise
specified, comparisons are made for 2012 and all prices are converted into
Euro/MWh using the annual exchange rate of the ECB (average of period).
One major caveat when dealing with
international comparisons is the lack of a common harmonised data source for
retail prices for electricity and gas. A wide variety of reputable sources of
data have been used and validated as far as possible (see sources and explanatory
notes under each chart). Nevertheless, different countries apply different
reporting standards and conventions, inter alia with regard to categories of
consumers. In addition, industrial retail prices can vary significantly within
countries and industrial sub-sectors – both in the EU and in other economies. 
This chapter does not take into account
exemptions and preferential prices - neither in the EU nor in other economies
as data is scarce and information difficult to quantify in a global comparative
context. Wherever possible, industrial prices are presented net of recoverable
taxes, while household prices include all taxes and duties. When it comes to
large and very large consumers, the reported retail prices (by Eurostat and
other international bodies and data providers) for electricity and gas may in
fact be considered a conservative overestimate. This holds both for retail
prices within the EU reported to Eurostat and for retail prices of other
economies.  Large consumers may purchase directly from wholesalers and be
partially or completely exempt from certain network charges, taxes and levies
that are nevertheless reported as non-recoverable in general electricity and
gas retail price statistics. 
Due to the considerable divergence in
levels of retail prices paid by industrial and residential consumers across the
EU, in international comparisons three retail prices are presented for each
consumer group in the EU: weighted average, highest and lowest. This is done
because the difference between the highest and the lowest priced country in the
EU is often in the order of magnitude of 3-4: beyond 4 in the case of
residential gas (incl. all taxes) and below 3 in the case of industrial gas
prices (ex. VAT and other recoverable taxes). 

3.2.1.     
Electricity retail prices 

In 2012, in 18 EU Member States industrial
electricity prices (ex. VAT and other recoverable taxes) were below the EU
weighted average. The prices reported for the EU refer to medium-size
industrial and household consumers[16]. 
In 2012 industrial electricity prices
levels for medium-size industrial consumers in the 18 Member States below EU
weighted averages were comparable to those reported for industrial consumers in
economies like Norway, Turkey, China, Brazil, Ukraine and Mexico. In the remaining Member States prices were comparable to those in Japan (or higher, in the cases of Cyprus and Italy). Industrial consumers in countries such as New Zealand, India, Russia, Indonesia, US, Saudi Arabia and UAE paid prices below – in some cases
well below - these in the lowest priced EU Member State. 
On average in 2012, across the EU and
denominated in Euro, medium-size industrial consumers in the EU paid before
exemptions about 20% more than companies based in China, about 65% more than
companies in India and more than twice the price for electricity as companies
based in the US and Russia. Industrial electricity prices in Japan were 20% higher than those faced by average industrial European consumer. 
Middle East countries such as Saudi Arabia and UAE have by far the lowest prices: industrial consumers in Europe pay more than 3
times as much as industrial consumers in these countries. 
In 2012 industrial retail prices in China were almost twice as high as those in the US. The IEA points out that China's industrial electricity prices have increased significantly in recent years, largely
because of rising coal prices and cross-subsidies in favour of residential
consumers (IEA, WEO 2013). 
Data from the energy intensive case studies
presented in chapters 1 and 2 supports the retail price level data. A
comparison of 2 EU-based brick and roof tile producers shows that in 2012 on of
these plants paid 42% more for electricity than the Russian plant with
comparable characteristics, while the other EU-based plant paid almost twice as
much as the Russian plant. Comparison of two EU-based brick and roof tile
producers in 2012 shows that one of these paid for electricity 2.7 times as
much as a US-based plant, while the other paid 10% more than the US-based
competitor.  The Russian brick and roof tile producer paid 54 Euro/MWh in 2012,
while the US-based brick and roof tile producer paid 69.1 Euro/MWh (ENTR,
CEPS).
In the case of wall and floor tiles,
electricity prices paid by two EU-based producers were 2.2 to 2.6 times these
in the plant in the US. The price gap between one Russian plant and the  two
EU-based plants is in the range of factor 8.5 to factor 10. A comparison
between the price paid by the Russian-based brick and roof tile producer and
the Russian-based wall and floor tile producer shows that the former paid for
electricity 54 Euro/MWh, while the latter only 9 Euro/MWh, which suggests
preferential treatment of the wall and floor tile producer used in this
comparison. A comparison between the electricity prices paid by three steel
producing plants in the US (one BOF, one EAF, and one rolling mill) and
EU-based steel makers points that in 2012 EU-based plants paid twice as much
for electricity as US-based ones. Error! Reference source not found. illustrates
these comparisons. 
Figure 11. Retail prices of electricity in
2012: industrial consumers 
Note: EU electricity prices for industry refer to
consumption band IC, exclusive of VAT and other recoverable taxes. Electricity
prices for industry for Canada refer to 2010 and for Korea to 2009. ECB annual
exchange rates have been used. Industrial prices exclude taxes as reported by
ERRA for Nigeria, Russia and Ukraine, by ANEEL for Brazil, by the IEA for Japan, Canada (2010) and New Zealand. IEA reports zero taxation of industrial prices for Mexico; ERRA reports zero taxation for Saudi Arabia and UAE. No data on taxation of industrial
prices in South Korea (IEA); until 2009 natural gas prices reported by South
Korea indicated  12-14% taxation of industrial natural gas prices. Prices
reported by CEIC for China are actual averages of industrial use electricity
prices in 36 cities; no consumption taxation on industrial retail prices in
China, but prices include production tax (17% for electricity, 13% for gas,
note that these are production taxes). Australian values are exclusive of
general sales tax (GST). EIA numbers for the US include state and local taxes;
electricity consumption is not taxed at the federal level in the United States,
but it is taxed in some states.
Sources: Eurostat (EU, Turkey and Norway), CEIC
(China), ANEEL (Brazil), ERRA (Russia, Saudi Arabia, Nigeria, Ukraine and
United Arab Emirates, data provided in Euro), Ministry of Finance of India
(India), IEA (Japan, Korea, Canada, Mexico, New Zealand, Canada), EIA (USA),
Australian Energy Market Commission (residential prices in Australia). 
Households in the EU on average paid prices
comparable to those in Norway, New Zealand and Brazil. On the other hand,
European households on average paid more than twice as much as US households. 
Figure 12.
Retail prices of electricity in 2012: residential consumers 
Note: EU, Turkey and Norway household prices refer to
consumption band DC, including all taxes. Residential prices include all taxes
and levies, as reported by the respective sources. ECB annual exchange rates
used. 
Sources for the two electricity retail price charts:
Eurostat (EU, Turkey and Norway), CEIC (China), ANEEL (Brazil), ERRA (Russia,
Saudi Arabia, Nigeria, Ukraine and United Arab Emirates, data provided in
Euro), Ministry of Finance of India (India), IEA (Japan, Korea, Canada, Mexico,
New Zealand, Canada), EIA (USA), Australian Energy Market Commission
(residential prices in Australia). 

3.2.2.     
Gas retail prices

On average and denominated in Euros, in
2012 medium-sized industrial consumers in the EU paid four times as much for
gas as industrial consumers in the US, Canada, India and Russia and about 12%
higher retail prices than those in China. Prices in the 10 Member States where
industrial prices were below the EU weighted average paid prices comparable to
those in Ukraine, China and Turkey. Industrial gas prices in Brazil and Japan
were above the EU weighted average.  
In the case of households, EU average
prices were 2.5 times higher than these faced by households in the US and
Canada, but were half the level of gas prices faced by households in Japan and
30% below those in New Zealand. Households in 14 Member States paid less than
the EU weighted average in 2012, putting their prices at levels comparable to
these in South Korea, Turkey and the US. 
This is indeed re-confirmed by the case
study data from two EU-based bricks and roof tile producers that pay about
3.7-3.9 times as much for gas as a similar plant in Russia. The comparison of
two other EU-based plants producing bricks and roof tiles point that these pay
for gas 2.8-3 times as much as a similar US-based plant. A of two wall and
floor tile producers in the EU point to a difference in the range of 3-4 times
with natural gas prices paid by a Russian plant. A comparison between two
EU-based wall and floor tile plants and a US-based plant point to a natural gas
price difference in the range of 3.6-3.7 times. A comparison of prices paid by
three steel-making plants in the US (one BOF, one EAF and one rolling mill)
with the prices paid by EU-based steel makers in the sample (see Annex 2) also
point that EU-based producers paid four times as much for natural gas than the
three US-based plants. In the case of ammonia, the steep fall in natural gas
price in the US transformed it from a marginal producer to one of the
lowest-cost producers in the world. Error! Reference source not found. illustrates
these comparisons.
Figure 13.
Retail prices of gas in 2012: industrial consumers  
Notes: Australia 1 refers to prices paid under new
contracts by large industrial consumers; Australia 2 means prices paid by small
business consumers and by households, respectively and is based on information
on standing offers (default tariffs, exclusive of general sales tax). Prices
for Korea and Japan refer to 2011. Prices for Japan, Ukraine, China, Turkey,
New Zealand, Russia, Canada and the EU exclude VAT (in the case of EU and
Turkey also other recoverable taxes, if any). Prices for Korea (2011) and the
US include taxes. No data on taxation in India. The price for Brazil includes
federal taxes as PIS and COFINS (social contribution taxes) and state taxes
such as ICMS (tax on circulation of goods and services; no value-added or
general sales tax in Brazil) which has different rates for each state. In June
2013 the government of India approved a new pricing formula for gas proposed by
the Rangarajan Committee, which is expected to double natural gas prices
starting from April 2014.
Sources: Eurostat (EU and Turkey), CEIC (Brazil,
China), ERRA (Russia, Ukraine), IEA (Japan, Korea, New Zealand, US, Canada),
KPMG (India), Australian Industry Group (Australia 1 = large industrial
consumers, new contracts) and Office of Tasmanian Economic Regulator (Australia
2 = small business consumers) 
Figure 14. Retail
prices of gas in 2012: household consumers 
Note: Data for Korea and Japan refers to 2011. Prices
include all taxes. 
Sources: Eurostat (EU and Turkey), CEIC (China), ERRA
(Russia, Ukraine), IEA (Japan, Korea, New Zealand, US, Canada, Mexico),
Australian Energy Regulator (household consumer prices)
 

3.3.           
Retail price evolution[17] 

Looking at the evolution over time of the
real index of industrial electricity prices, one can see that between
2008 and 2009 industrial consumers in OECD Europe faced an increase in
electricity prices of about 10%. In real terms the index of industrial
electricity prices stayed fairly stable between 2009 and 2012. All in all,
between 2008 and 2012 industrial consumers in OECD Europe faced an increase in
electricity prices of almost 10% in real terms[18].
In comparison, the real index of industrial
electricity prices is down by 10% in 2012 in comparison to 2008, with the
biggest drop coming in the period 2010-2012. 
Between 2008 and 2012 the respective national
indices of industrial electricity prices increased by 4% in Canada, 14% in
Korea and Japan, at 19% in Australia. 
Year on year in the first quarter of 2013,
the IEA reports that the real price index of industrial electricity prices went
up by most in Ireland (+20.3%), Italy (+13%) and Turkey (+10.9%), while the
biggest drop across OECD countries was in Poland (-4.9%).
Figure 15. Index
of real electricity prices for industrial end-users (2008=100)
Source: IEA,
European Commission calculations 
Note: The indices have been re-referenced (re-based) to
year 2008 from the original calculation of the IEA that uses 2005 to fit the
overall timeline of the price analysis (2008-2012). The IEA computes the real
price index from prices in national currencies and divided by the country
specific producer price index for the industrial sector and by the consumer
price index for the household sector.
The divergence in the evolution paths is
even greater when it comes to industrial prices for natural gas. Industrial gas
price indices show that users in Canada and the US are now benefiting from
prices comparable in real terms to those in mid-90s (in the case of US) and
late 90s (in the case of Canada) which decreased by more than 60% between 2008
and 2012. 
In 2012 the index of real natural gas
prices for industrial users was at its level of 2008. Industrial users in Japan
and Korea saw the steepest growth in gas prices, with 2012 prices standing 32%
and 39% above their respective 2008 levels.
IEA analysis shows that in the first
quarter of 2013 year on year the real price index of industrial end-use prices
for gas rose most in Turkey (+30.5%) and New Zealand (+18.9%) and fell most in
Slovenia (-15.3%) and the Slovak Republic (-5.6%).
Figure 16. Index
of real natural gas prices for industrial end-users (2008=100)
Source: IEA, European Commission calculations 
Note: The indices have been re-referenced (re-based) to
year 2008 from the original calculation of the IEA that uses 2005 to fit the
overall timeline of the price analysis (2008-2012). The IEA computes the real
price index from prices in national currencies and divided by the country
specific producer price index for the industrial sector.

3.4.           
Retail price composition: examples

Below we attempt to decompose retail prices
for electricity and gas in some major economies. Ideally the aim was to
decompose retail prices into the same components as the ones used in our decomposition
analysis of European retail prices. In reality this is not always feasible as
different countries provide profoundly different degrees of disaggregation. 
The comparison of household electricity
prices shows that the energy component in Germany and especially in the UK
tends to be at levels much higher than in the US, Australia and Turkey. The
network component in Germany and France is higher than in the US, while in the
UK and Turkey it is lower than in the US. Australia stands out as a country
with exceptionally high network costs as well as other charges. Estimates based
on data from the Australian Energy Regulator show that more than a fifth of the
household electricity bill comes from retail and energy scheme costs -
including the 'shop front' for a consumer's electricity supply and costs from
schemes for energy efficiency and renewables, as well as carbon costs. 
Table 1. Breakdown of household electricity prices 
   || US (2011) || Australia || Turkey || Germany || France || UK 
   || Eurocent/kWh 
 energy || 5.8 || 7.6 || 8.3 || 8.5 || 5.3 || 13.4 
 network || 4.2 || 11.0 || 3.4 || 5.9 || 5.0 || 3.6 
 taxation || n.a. ||   || 3.0 || 12.4 || 4.2 || 0.9 
 other ||   || 5.2 ||   ||   ||   ||   
 Total || 10.0 || 23.9 || 14.7 || 26.8 || 14.5 || 17.8 
Source:
Eurostat for Germany, France, UK and Turkey, second half of 2012. Notes: United
States: electricity - 2011 data from EIA Annual Energy Outlook 2013.
Transmission accounts for 1.1 Eurocent/kWh, distribution accounts for 3.1
Eurocents/kWh. No data on taxation. Australia: European Commission calculations
based on data on household price levels published by the Australian Energy
Market Commission (Electricity Price Trends Report 2013) and  breakdown of
household bills by the Australian Energy Regulator (State of the Energy Market
2012). Other costs: in the case of electricity in Australia these include
carbon costs, green costs and retail costs.
In the case of prices of natural gas for
households, the energy component in Germany, France and the UK is much higher
than in the US and Australia[19]. The network component in Germany, France and the UK is much higher
than in the US, but much lower than in Australia. 
Table 2. Breakdown of household gas prices
   || US || Australia || Germany || France || UK 
   || Eurocent/kWh 
 energy || 0.7 || 2.0 || 3.6 || 3.4 || 3.6 
 network || 0.9 || 4.5 || 1.7 || 2.4 || 1.5 
 taxation || 0.1 ||   || 2.2 || 1.1 || 0.5 
 other || 1.1 || 2.1 ||   ||   ||   
 Total || 2.8 || 8.6 || 7.4 || 6.8 || 5.6 
Source: VaasaETT
for Germany, France and UK, prices in capital cities in 2012. United States:
European Commission calculations based on data on household price levels by the
EIA and breakdown of household bills by the American Gas Association. Other
costs: in the case of Australia these include retail costs and carbon costs. In
the case of the US these include net interest, other and net income,
depreciation and amortisation, administrative and general, customer accounts,
bad debt.
When looking at the share of network
charges in EU retail electricity prices, it is worth noting that in a ranking
of 144 countries undertaken by the World Economic Forum on quality of
electricity supply, 5 of the top 10 positions are occupied by EU Member States.
There remain differences between Member States, with 15 EU Member States in the
top 30 (NL, DK, AT, UK, FR, FI, SE, BE, LUX, CZ, IE, DE, SK, PT, SI, ES) ,
while the remaining 13 rank lower down the list with RO and BG in positions 88
and 95 respectively.  
Table 3. Quality of electricity supply globally

3.5.           
Energy taxation

Globally, countries differ in the way they
tax energy in terms of the range of products taxed, definitions
of tax bases, tax rate levels and rebates and exemptions. There are often
substantial differences in the way in which different forms, uses and users of
energy are taxed. While EU industry generally pays lower rates of taxation on
energy products in comparison to households, the share of tax in the total
energy price for industrial users remains high in some EU countries, especially
in the case of electricity. This in many cases is moderated by various
exemptions and preferential tax treatment of industrial consumers meeting
certain criteria[20].    
In a global comparative context, EU Member
States tax electricity and natural gas more heavily than other global
competitors and also more heavily than other economies that face high energy
prices, such as Brazil and Japan. For example, the share of tax in industrial
electricity prices in Germany is five times as high as in Japan and more than
double than it is in Brazil (Table 4). On the other hand Brazil and China
tax natural gas for industrial use more heavily than Germany and France.
Table 4. Share of tax in industrial energy prices in selected countries,
2012
Source: IEA WEO
2013 and sources therein.
Some major economies have lower
consumption-based taxes on electricity and gas (VAT, general sales tax): for
example Japan has a 5% VAT on electricity and gas and South Korea has a 10%
rate on electricity. General sales taxes levied by the states in the US are in
the range 2-6%. In comparison, in the EU VAT rates for electricity and gas
range from 6% in Luxembourg to 27% in Hungary.    
Figure 17. VAT rates on natural gas and
electricity 
Source: IEA Energy Prices and Taxes, 2013Q2

The OECD has looked into the effective tax
rates on electricity and natural gas across all OECD members[21]. In Australia the consumption of electricity is not taxed. Most
electricity producers are required to pay the carbon price (set at AUD 23
per tonne of carbon emitted and rising 2.5 per cent per annum in real terms[22]). Natural gas for heating and process use is untaxed (OECD 2013).
In Canada the consumption of electricity
and fuels used to produce electricity is not taxed federally except where the
electricity is used primarily in the operation of a vehicle. Natural gas is not
taxed at federal level (only British Columbia has a tax on natural gas) (OECD
2013).
Japan taxes the consumption of electricity
taxed at a rate of 375 JPY/MWh (less than 4 Euro/MWh). In addition,
fuels used for electricity production are taxable under the petroleum and gas
tax. For energy used for heating or process purposes, natural gas and petroleum
gases are taxed at 1,080 JPY/tonne (about 10.5 Euro/tonne) (OECD 2013).
South Korea taxes fuels used to generate
electricity, but not the consumption of electricity. An individual consumption
tax is applied to LPG and natural gas (including liquefied forms) on a per
kilogram basis. An education tax also applies to LPG (butane gas) on the same
basis. 
Electricity consumption is not taxed at the
federal level in the United States but is taxed in some states (OECD 2013).
Due to the generally lower tax burden on
energy consumption outside the EU, it can be expected that the importance of
energy-related tax exemptions is much smaller. 

3.6.           
Energy price subsidies

Increasing global competition and
integration of production chains are developments with far-reaching social,
political and economic consequences. Various stages of production may be
offshored to countries with less stringent or unenforced regulations or ones
that subsidise energy.   
At the global level, much remains to be
done to phase out inefficient fossil-fuel subsidies that encourage wasteful
consumption. Even though the large part of fossil fuel subsidies are focussed
on oil and petroleum products, the IEA's 2013 World Energy Outlook quotes the
results of a survey of 40 countries, showing that in 2012 subsidies to natural
gas and coal consumed by end-users amounted to 124 billion USD and 7 billion
USD respectively, while subsidies to electricity stood at 135 billion USD[23]. Iran, Saudi Arabia, Russia, India, Venezuela and China are the
countries with the highest levels of subsidy to fossil fuels. 
Significant subsidies to natural gas and
electricity in major economic partners for the EU, such as Russia, India and
China, does little to establish a level-playing field to for consumers based in
different parts of the world. 
At the same time, the IEA signals that
several major reforms to reduce or phase out fossil-fuel subsidies have been
announced since 2012, increasing the momentum of recent years on this issue.
These include reforms to energy pricing made by India and China. India has
announced that power stations that need to buy imported coal will be able to pass
on the extra costs to their customers[24]. India has also announced that prices of domestically produced
natural gas will be adjusted on a quarterly basis from April 2014, to match the
average of the prices of the LNG it imports and of gas on other major
international markets. According to the IEA, this is expected to result in a
doubling of domestic gas prices. 
In 2013 China increased natural gas prices
by 15% for non-residential users. In a move to ease electricity shortages, in
July 2012 the country implemented a tiered electricity pricing system for
households whereby customers who use more electricity will pay higher rates per
kilowatt-hour than those who use less. Russia raised electricity and gas prices
by 15% on average in July 2013 and plans to increase them further in July 2015.
Figure 18.
Economic value of fossil-fuel consumption subsidies by fuel for top 25
countries, 2012[25]
Source: IEA WEO
2013
  

3.7.           
Energy and cost competitiveness

The current difficult economic climate
exacerbates concerns about loss of competitiveness. Competitiveness is a broad
macro-economic concept related to quality of living and different from the
notion of cost competitiveness. For example, the 2012-2013 Global
Competitiveness Index (GCI) of the World Economic Forum ranks 144 economies on
a set of 12 pillars of competitiveness grouped in three sub-indexes: basic
requirements, efficiency enhancers and innovation and sophistication. Global
competitiveness implies a comparison of performance with trade partners and
market shares in world markets. In contrast, cost competitiveness applies more
specifically to input factors. 
Many factors drive productivity and
competitiveness, from macroeconomic environment, infrastructure and
institutions to health and education systems, goods and labour market
efficiency, market size, technological readiness and innovation[26]. 
The price of energy – together with cost of
labour, capital and raw materials – affect overall production costs and the
profitability of economic actors. Rising energy prices and volatility are a
factor with direct impact on businesses' production costs, their economic
activity, external accounts and competitiveness.
A comparison of the cost-competitiveness of
different geographical locations needs to take into account the cost elements
that vary between those locations. One of the major drivers of energy costs is
energy price; the price of energy commodities like gas and (to a lesser extent)
electricity differs substantially across locations. For this reason, regional
disparities among energy prices are often centre stage in debates about
competitiveness, even more so in countries and regions dependent on imports.
The extent to which a country is vulnerable
to energy price increases, relative to other economies, depends on the
structure of its economy, in particular its share of energy intensive
manufacturing, the energy efficiency of its manufacturing sectors and
sub-sectors and its degree of energy dependence. 
The significance of energy to competitiveness
also varies between industries, segments and sub-segments of the global value
chain, depending among other things on the energy intensity of manufacturing
processes and the degree to which manufactured products are globally tradable
(ease and cost of transportation). 
Energy costs are particularly important for
the international competitiveness of energy intensive industries, which often
have a strategic position in the economic value chain. Energy costs as a share
of total production costs vary significantly by sectors and region. For
example, the IEA shows that the share of energy costs in the production of
organic chemicals varies between approximately 50% and over 80%, with the share
in Germany and Japan higher than that in the US. In other cases, such as glass
and glass products, the share of energy costs in total production costs ranges
up to 20%, with German and Japanese manufacturers in the lowest band of this
range.   
Figure 19. Share
of energy in total production costs by sub-sector, 2011
Source: IEA WEO 2013 and sources therein. Note: To
calculate the share of energy in total production cost, IEA has used official
sources for the USA, Germany and Japan for all industrial sub-sectors apart
from primary aluminium in Germany (estimated based on the US data accounting
for differences in electricity prices and specific energy consumption). 
As of 2011 the EU dominates the export
market for energy-intensive goods, accounting for more than two-thirds of
export value, which makes it the largest export region for energy intensive
goods. 
The effects of energy prices on the EU's
international competitiveness differ by product and trading partner; they are
difficult to isolate from the effects of other cost factors and to quantify on
the basis of statistical time series. In addition it may be difficult to
empirically establish and monitor global industrial shifts related to regional
energy price disparities, due to the lead times associated with production and
investment decisions and time lags with statistical data on manufacturing
output, trade flows, employment statistics and retail prices of energy. 
Despite these analytical challenges, one
can expect that regional price disparities increase the risk of reduced
production levels and investment in higher priced countries and bring changes
in global trade patterns, in particular affecting industries that have a high
share of energy costs and are exposed to international competition because
their production is easy and relatively cheap to transport[27]. 
This is supported by analysis undertaken by
the IEA in the 2013 World Energy Outlook, which shows that persistently high
energy price disparities can lead to important differences in economic
structure over time and have far-reaching effects on investment, production and
trade patterns. For example, IEA projections to
2035 point to marked differences in production and export prospects for the
energy-intensive sectors across regions determined by their stage of economic
development – with strong domestic demand for energy intensive goods in some
emerging economies – but also by energy price levels, particularly through
relative energy costs among developed countries.  Projections show that in 2035
the EU will remain the leading exporter of energy-intensive goods, exporting
more than the US, China and Japan together, but that in 2035 market shares
in global export markets for energy intensive goods of the EU decline - by
10 percentage points in the case of chemicals in the EU and by 9 percentage
points in the case of non-ferrous metals - as opposed to developing Asia that
is projected to increase its export market share to a level equal to that of
the EU. A combination of factors drive this trend, including energy prices,
relatively high wages and longer shipment distances to growing consumption
centres in Asia (IEA WEO 2013). 
Figure 20. Regional shares of global export market
and growth in export values in the chemicals and non-ferrous metals sectors,
New Policy Scenario of the IEA (2011-2035)
Source: IEA WEO 2013
A recent study by the Boston Consulting
Group (BCG) indicates that the US already has a production costs advantage
compared with other developed economies that are leading manufacturers[28]. Due to three factors – labour, electricity and natural gas – by
2015 average manufacturing costs in the UK, Japan, Germany, France and Italy
will be 8-18% higher than in the US. BCG's projection shows that by 2015
average labour costs in the US will be around 16% lower than in the UK, 34%
lower than in Germany and 35% lower than in France and Italy. BCG expects that
the gap between electricity and gas prices in the US and major European
economies will remain or even increase by 2015. 
Figure 21.
Average projected manufacturing cost structures of the major exporting nations
relative to the US in 2015
Source: BCG
2013
Impacts on US shale gas on trade[29] 
Besides its downward pressure on domestic
gas and electricity prices, the most evident effect of shale gas development in
the US has been a fundamental contribution to the sizeable reduction of the US
energy trade deficit over the past few years (about 1%-point of GDP). While the
US gas trade has tended to move closer to balance, the coal trade surplus has
increased since its consumption has been displaced by cheaper natural gas. This
means that the current energy trade deficit of the US corresponds only to its
trade deficit for oil (about 2% of GDP). On the contrary, in the EU the trade
deficits for natural gas, oil and coal kept on growing,. 
The repercussion of the surge in shale gas
production is less visible when looking at the overall current accounts of the
two regions. The EU-US goods balance shows a persistent surplus for the EU
without any clear sign of deterioration. This may indicate that until 2012 the
EU-US energy price gap has not visibly affected the export capacity of the EU
industry and their competitiveness vis-a-vis their US counterparts. In
addition, the EU in 2012 had a current account surplus while the US ran a
consistent deficit.
Figure 22. Current account balance, external balance
of goods and bilateral balance of goods, 2001-2012 - US and EU
Source: DG ECFIN. Energy Economic Development in
Europe. 
While the surge in US shale gas has led to
significant changes in the US energy sector, reducing the US energy trade
balance in GDP terms and its energy dependency, the impact on the EU so far can
be considered limited; no major shift in the EU-US goods trade balance has been
observed yet, nor are there any significant divergent trends in the overall
production structure of manufacturing industry which can be ascribed to the
shale gas revolution.
The resilience of the EU industry can be
explained at least partially by better performance in terms of energy
intensity, which may have helped to buffer the persistent energy price gap.
However the relatively small decline in energy intensity sectors' share in
total EU GVA signals that not all the industrial segments have been equally
able to maintain their performances. 
These observations should not however lead
to complacency. Future developments will depend largely on how the energy price
gap evolves. A reduction in price differences may come with the beginning of
gas exports from the US and/or the depletion of the cheapest shale gas basins.
At the same time, however, EU industry may have less margin for further energy
intensity improvements, and US counterparts may be able to catch up in this
respect. Reducing EU energy dependency would help to offset the effects of
energy price fluctuation and security of supply risks. Finally, the pace of the
EU's economic recovery will play a fundamental role in determining its capacity
to withstand global competition. 
Energy costs in a global comparative
perspective[30]
To compare the role of energy in production
processes globally and evaluate the role of energy in competitiveness, one
needs to explore the interaction between energy costs, energy prices and energy
intensity. One way to do this is by looking at the level and evolution of the
so-called real unit energy cost, which measures the amount of money spent on
energy sources needed to obtain one unit of value added.[31] 
The level of real unit energy cost
indicates the importance of energy inputs and sensitivity to energy price
shocks – a greater increase in some countries/sectors than others can signal an
increased vulnerability to energy costs in a particular sector, but could also
indicate a restructuring of production towards more energy intensive production
processes. It is therefore important to also analyse the drivers of real unit
energy costs: energy intensity and the real price of energy (which measures
energy inflation above sectoral inflation). A shift-share analysis can shed
further light on the role of restructuring in energy cost developments.
A global comparison of real unit energy
costs in the manufacturing sector[32] shows that in the period 1995-2011energy costs increased not
only in the EU but in the rest of the world as well. The EU manufacturing
sector as a whole enjoyed some of the lowest real unit energy costs together
with Japan and the US. This means that to obtain 1 USD of valued added at the
level of EU manufacturing as a whole, businesses spent less money on energy
sources than counterparts in Russia or China. 
Certain sectors in the EU however show a
significant vulnerability in a global comparison, because of high real unit
energy cost levels and/or growth rates, indicating elevated sensitivity to
energy-cost pressures. For example, the production of coke, refined petrol
and nuclear fuel is the sector that shows the worst performance in the EU, with
real unit energy costs several times above levels in the US, Japan, China and
Russia and increasing between 1995 and 2011 unlike any other country
analysed (US, Japan, Russia and China).
Energy prices in the EU and Japan are
among the highest in a global comparison (see
section 3.2 on price levels and 3.3 on price evolution), while the US and China
experienced consistently lower energy prices throughout the period 1995-2009[33]. At the same time, the EU manufacturing sector, together with
Japan, showed the lowest energy intensity levels – probably partially
linked to the declining share of energy-intensive industry in total industrial
output and to EU manufacturing specialising in low energy intensity and high
value added production – which generally explains the low real energy unit
costs observed in the EU. The US and China have been catching up in terms of
energy intensity improvements but the difference in absolute levels remains
substantial.
Figure 23.
Evolution of real unit energy costs as % of value added, manufacturing sector
(1995-2011)
Source: DG ECFIN. Energy Economic Development
in Europe.
Figure 24.
Evolution of real energy prices in the manufacturing sector (1995-2009)
Source: DG
ECFIN. Energy Economic Development in Europe.
Note: Real
energy prices are defined here as the USD value of 1 unit of the energy
inputs used by the manufacturing sector measured in 2005 USD.
A shift share analysis of the evolution of
real unit energy costs shows that in the period 1995-2011 increasing energy
costs were driven by cost increases within manufacturing subsectors worldwide.
The only exception is the US, which experienced a significant restructuring
towards high energy cost production. The shift share analysis confirms that
in 2005-2011 there is evidence of EU industry restructuring away from
energy intensive sectors.  The increase in energy costs was the steepest
in the EU (relative to the other countries in the scope of the analysis)
and this increase in energy costs was associated with EU industry restructuring
towards low energy intensity. In comparison, in the US the energy cost increase
was much less pronounced. 
Between 2005 and 2011, EU manufacturing
saw the highest increase in energy costs within subsectors in a global
comparison. As a result of this unparalleled
increase in energy costs within subsectors the EU witnessed a move towards
subsectors with low energy costs. These developments follow similar trends in
the period 1995-2000 characterised by a marked increase in real unit energy
costs dominated by the within subsector effect - indicating pure energy cost
pressure - in the EU, US and Japan. The period 2000-2005, however, was
significantly different, with the US being the only country with a negative
within subsector effect. At the same time the US showed a very large positive
restructuring effect mitigated to some extent by a negative interaction term. Overall
this indicates that the US had already started specialising in high energy cost
production in the period 2000-2005[34]. Finally, the last period – 2005-2011 – includes the 2008 peak in
oil prices and subsequent fall in 2009 and has brought a significant adjustment
and restructuring on a global scale. 
In the US, the increase in real unit energy
costs during this period was due to a combination of considerable real unit
energy cost growth within subsectors and a positive restructuring effect. The
increase, however, has been significantly smaller in the US than in the EU.
Japan saw a positive within subsector effect with a positive restructuring
effect. Finally, China experienced positive but modest within subsector effect
and a similarly modest negative restructuring effect.
Figure 25. Shift share analysis of real unit
energy costs in the manufacturing sector (1995-2011)
 || 
 || 
Source: DG ECFIN. Energy Economic Development
in Europe.
Note: The within
subsector effect shows what would be the growth of real unit energy costs
of the total manufacturing sector if the shares of the subsectors had
stayed unchanged throughout the period of analysis. Therefore this effect shows
the pure energy cost pressure filtering out the effect of restructuring. The restructuring
effect measures the contribution of changes in value added shares of the
different subsectors to overall manufacturing real unit energy cost growth
keeping the real unit energy costs of subsectors unchanged. This component
therefore shows the static restructuring effect. A negative restructuring
effect could show that the share of industries with high energy costs has
fallen. The interaction effect captures the dynamic component of
restructuring by measuring the co-movement between real unit energy costs and
value added shares. If it is positive, it signals that energy costs are rising
in subsectors that are expanding, and/or they are falling in shrinking sectors,
i.e. the two effects complement each other. If it is negative, then real unit
energy cost growth is positive in shrinking sectors, and/or negative in
expanding sectors, i.e. the two effects are offsetting each other. A negative
interaction effect could signal that businesses in a country are reallocating
resources from high to low energy cost sectors in response to rising energy
costs.
If the refinery sector is excluded from the
above calculation of the real unit energy cost[35], the levels decrease substantially (more than halved) and the
ranking of the countries changes with the US displaying the lowest level of 
unit costs, followed by the EU and Japan. This result indicates the importance
of the refining sector in the US and it also highlights the fact that in the
other industrial sectors, less dependent on oil, the real unit energy cost
level is somewhat higher in the EU than in the US. However, even excluding the
refinery sector, the unit cost in the EU remains among the lowest in the world.
While the restructuring observed in the shift-share analysis of the
manufacturing sector seems to have been driven largely by developments in the
refinery sector, the method does not capture any potential restructuring taking
place at a lower aggregation level than the 2-digit NACE sectoral breakdown.
International energy efficiency trends
The importance of energy efficiency as a
competitiveness factor is growing over time with globalisation. Energy prices
and energy intensity are the two drivers of real unit energy costs. Increasing
energy efficiency provides the means for economic actors to partially
counterbalance the impact of increasing energy prices. 
Analysis by the IEA in the 2013 World
Energy Outlook points to diverging energy intensity developments by sector at a
regional level.  
Industrial energy intensity in the EU saw a
decline of about 15%, partially linked to the declining share of
energy-intensive industry in total industrial output. Energy intensity levels
in Japan’s industry sector decreased by about 9% from 2005 to 2012, helped by
structural changes in the economy away from energy-intensive sectors. 
In the United States, energy intensity in
industry as a whole decreased only slightly in the period 2005-2012, as
efficiency improvements were almost fully offset by increased oil and gas
production and increased activity in the chemicals industry which shifted the
economy, to some extent, to more energy-intensive sectors. 
In contrast, the bulk of China's decrease
in industrial energy intensity can be attributed to energy efficiency gains.
During the 11th Five-Year Plan (2006-2010) the share of energy-intensive
industries in total industrial value added did not change significantly, due to
strong growth in cement and steel production. Efficiency improvements were
strongest in the cement and paper industries.
Figure 26.
Energy intensity change by sector and region (2005-2012)
Source: IEA WEO
2013
The intensity of industrial sectors such as
iron, steel and cement is lower in Europe than elsewhere, whereas for sectors
such as petrochemicals and pulp and paper it is higher (Figure 27). Differences in energy intensity
at sub-sectoral level are explained by efficiency improvements, along with differences
in production processes and types of products.
 
Figure 27. Energy intensity by sub-sector and
region, 2011
Source: IEA WEO 2013
Projections from the IEA's World Energy
Outlook point to a narrowing of the energy intensity gap between North America
and Europe, with roughly half of global efficiency-related energy savings
between 2011 and 2035 achieved in China, North America and Europe, with the
largest savings coming from China (in particular due to a shift from energy-intensive
industries to light industry and services) and North America (more ambitious
energy efficiency policies in transport, industry and buildings). 

3.8.           
Chapter conclusions 

While Europe has never been a cheap energy
location, in recent years the energy price gap between the EU and major
economic partners has increased substantially. Over time manufacturing in the
EU has undergone a restructuring towards lower energy intensity and higher
value added production, while relatively high energy prices have incentivised
improvements in energy efficiency. The extent to which
a country is vulnerable to energy price increases, especially relative to other
economies, depends on the structure of its economy. The share of energy
intensive manufacturing in its economy, the energy efficiency of manufacturing
sectors and sub-sectors and its degree of energy dependence all play a role. 

 Persistent regional energy price
     disparities cause changes in global trade patterns. For industries with a high share of energy costs and exposed
     to international competition because products are easy and cheap to transport,
     they increase the risk of reduced industrial manufacturing growth or even
     in production levels and investment in higher priced countries. 
 Between 2005 and
     2011, EU manufacturing saw the highest increase in energy costs within
     subsectors relative to the US, China and Japan. 
 The low energy intensity of EU
     manufacturing cannot be considered apart from its relatively high energy
     prices. The decrease in energy intensity can be attributed to EU
     manufacturing specialising in low energy intensity and high value added
     production.
 Certain sectors in the EU show
     significant vulnerability to energy price levels because of their high
     real unit energy cost levels and/or growth rates in a global comparison 
 There is evidence of EU industry
     restructuring away from energy intensive sectors in the period 2005-2011;
     developments in the refining sector have had a very large impact on the
     restructuring observed. 
 The level of real unit energy costs in
     the EU is somewhat higher than in the US[36]. The increase in real unit energy costs in the period
     2005-2011 was the steepest in the EU relative to other countries in the
     scope of the analysis and this increase in energy costs was associated
     with EU industry restructuring towards lower energy intensity. Energy cost
     increase in the US was much less pronounced. 
 The importance of energy efficiency as
     competitiveness factor is growing over time with globalisation. Despite their good efficiency performance, EU manufacturers
     have steadily improved their efficiency performance, converging towards
     Japanese levels. The US and China have been catching up even though the
     difference in absolute levels remain substantial.
 Europe is price-taker in global
     hydrocarbon markets (oil and coal). 
 Unlike internationally traded commodity
     markets, in particular crude oil and coal, natural gas has
     disparate regional benchmark prices. Over the recent years the gap between
     regional gas prices has widen driven by diverging regional gas price
     drivers.
 In recent years wholesale gas prices have increased in all world regions except North America.
     Europe and Asia Pacific remain the highest priced wholesale gas markets.
     This widening gap has been driven by factors such as the US shale gas
     boom, increases in oil-indexed gas prices in Europe and skyrocketing gas
     demand in Japan in the aftermath of Fukushima. Only in the Middle East and
     Africa, where prices are often held down to the cost of production or
     below as a subsidy, are average wholesale prices for gas lower than in
     North America. 
 Even within the EU, the difference
     between the lowest and highest wholesale gas price remains significant.
     Member States with a diverse portfolio of gas suppliers and supply routes
     and well-developed gas markets reap the benefits by paying less for
     imports and generally having lower prices. 
 Similar though less pronounced is the
     case of regional electricity prices. Regional
     differences in wholesale electricity prices are less
     pronounced than for gas, at least in major economies (data for US, Europe
     and Australia). The net effect of low US natural gas prices on the
     difference between US and EU electricity prices is mitigated by lower EU
     coal prices (as a result of cheaper gas in North America).
 Retail electricity for industry[37]: on average across the EU and denominated in Euro and in
     nominal terms (ex. VAT and recoverable taxes), in 2012 medium-size
     industrial consumers in the EU paid about 20% more than companies based in
     China, about 65% more than companies in India, more than twice as much as
     companies based in US and Russia and more than three times as much as
     Middle Eastern industrial consumers in e.g. Saudi Arabia and United Arab
     Emirates. Industrial electricity prices in Japan were 20% higher than these
     faced by the average industrial European consumer. 
 Retail electricity for households: on average European households paid more than twice as much
     as US households for electricity and comparable prices to Norway, New
     Zealand and Brazil. 
 Retail gas for industry: in 2012 medium-sized industrial consumers in the EU paid four
     times as much for natural gas as industrial consumers in the
     US, Canada, India and Russia and about 12% more than those in China.
     Industrial gas prices in Brazil and Japan (2011) were above the EU
     weighted average.  
 Retail gas for households: EU average gas prices were 2.5 times higher than those faced
     by households in the US and Canada, but were half the levels of gas prices
     faced by households in Japan (2011) and 30% below those in New Zealand.
     Households in 14 Member States paid less than the EU weighted average in
     2012, putting their prices at levels comparable to those in Turkey and the
     US. 
 Between 2008 and 2012 European industrial
     consumers faced a 10% increase in real terms in electricity prices.
 Other parts of the world, in real terms over the same period, saw more pronounced growth
     in electricity prices for industrial consumers (14% in Korea and Japan,
     19% in Australia, in some cases from a higher starting point). In the US
     there was a 10% decrease in real terms. 
 This divergence was even greater for
     industrial prices for natural gas. Industrial users in Canada and the
     US are now benefiting from prices comparable in real terms to these in the
     mid- and late 90s. Industrial users in European OECD countries are
     paying in 2012 prices comparable to 2008 levels in real terms. Industrial
     users in Japan and Korea saw the steepest growth in gas prices, with 2012
     prices 26% and 33% above their respective 2007 levels. 
 In a ranking of 144 countries globally on
     quality of electricity supply, 5 of the top 10 positions were
     occupied by EU Member States. 
 EU countries tax
     natural gas and electricity more heavily than
     some other major global competitors, such as the US and Canada. 
 At
     global level much remains to be done to phase out inefficient fossil-fuel
     subsidies that encourage wasteful consumption.

[1]  Nalbandian, H. and Dong, N. 2013. Coal and gas competition in
global markets. IEA Clean Coal Centre. 
[2] The Pacific market is made up of the utilities in Japan, South
Korea and Taiwan, as well as increasing trade going into China and now India;
Australia, Indonesia, and recently Vietnam, have been the main suppliers to
this market
[3] Uranium price indicators are developed by a small number of private
business organizations, like The Ux Consulting Company, LLC (UxC), that
independently monitor uranium market activities, including offers, bids, and
transactions. Such price indicators are owned by and proprietary to the
business that has developed them. The Ux U3O8 Price® indicator is one of only
two weekly uranium price indicators that are accepted by the uranium industry.
The Ux U3O8 Price® is used as the settlement price for the NYMEX UxC Uranium
U3O8 Futures Contract (UX ). 
[4] IGU 2013. Wholesale Gas Price Survey - 2013 Edition. A global
review of price formation mechanisms 2005 -2012
[5] In the survey of IGU North-West Europe is defined as UK, Ireland,
France, Belgium, Netherlands, Germany, Denmark
[6] In December 2012 a gas exchange was launched on the Polish Power
Exchange (PolPX)  and in January 2013 a gas exchange was launched in Hungary. 
[7] As indicated on Error! Reference source not found., data
from the 2012 annual survey on wholesale price mechanisms by the International
Gas Union shows that 44% of gas consumption in Europe was priced on a
gas-on-gas competition basis, as opposed to 51% which was still oil-indexed.
The share of oil-indexed volumes has gone down from representing almost 80% of
consumption in 2005 to 51% in 2012. Yet, strong regional differences persist in
price formation mechanisms with about 70% of gas in North-West Europe (defined
in the survey as UK, Ireland, France, Belgium, Netherlands, Germany, Denmark)
priced on a gas-on-gas basis in 2012,  compared to less than 40% in Central
Europe (Austria, Czech Republic, Hungary, Poland, Slovakia and Switzerland)..  
[8] See textbox and ECFIN 2013. Energy Economic Developments in Europe.

[9] The worst drought in decades depleted hydroelectric reserves in
Brazil and increased its LNG imports by a factor of three in the first four
months of 2013 as compared to the same period in 2012.
[10] Regional weighted averages. Significant differences among LNG
importers in the EU with Spain meeting around 60% of its gas demand by LNG and
Italy around 10%. Source: International Gas Union. World LNG Report - 2013
Edition
[11] Refers to the lower 48 state, e.g. to the US states located on the
continent of North America south of the Canadian border, which excludes the
states of Alaska and Hawaii. Washington D.C., is also included when the term is
used.
[12] In April 2012, wholesale prices in Texas spiked because of a sharp
increase in temperature near the end of the month.
[13] Australian Energy Regulator. State of Energy Market 2012. 
[14] On 13 November 2013, its first working day,
the new Government of Australia introduced the package of bills to repeal the
carbon laws, including the emissions trading scheme.
[15] Data as of September 2013. The comparison is made after converting
all prices in EUR/MWh using 2012 annual exchange rate of the ECB. 
[16] Electricity industrial: 500-2000 MWh annual consumption (Eurostat
band IC), electricity household: 2500 – 5000 KWh annual consumption
(Eurostat band DC), gas industrial: 10 000 - 100 000 GJ (Eurostat band I3) and
gas household: 20 – 200 GJ (Eurostat band  D2). 
[17] Arguably, over time exchange rates of
national currencies, as well as inflation levels, may account for a certain
level of fluctuation if one looks at price levels. Here we present IEA
industrial price indices in real terms (deflated with PPI) calculated in
national currencies. Therefore these figures are not affected by fluctuations
in exchange rates.
[18] IEA publishes retail price evolution data
for OECD Members only. OECD Europe excludes Bulgaria, Croatia, Cyprus, Latvia,
Lithuania, Malta and Romania.
[19] This holds also in case one assumes that some – or even all – of
costs classified under 'Other' should be included under the energy component. 
[20] Data on excise duty special regimes in the EU available here regiuhttp://ec.europa.eu/taxation_customs/resources/documents/taxation/excise_duties/energy_products/rates/excise_duties-part_ii_energy_products_en.pdf

[21] OECD. 2013. Taxing energy use in OECD countries. In: Taxing Energy
Use: a Graphical Analysis. OECD Publishing. The OECD report covers taxes such
as excises levied directly on a physical measure of energy product consumed and
excludes general taxes, such as VAT. The OECD methodology "looks
through" taxes on electricity consumption to calculate upstream the
implicit tax rates on the primary energy used to generate electricity.
[22] In November 2013 two years after Australia’s carbon price passed
parliament and almost 18 months after the initial fixed-price carbon tax took
effect, the House of Representatives has voted to repeal it. The fate of the4
repeal now rests with the Senate.  
[23] To estimate subsidies the IEA looks whether energy prices are set
below reference prices, which are defined as the full cost of supply based on
international benchmarks. The estimates cover subsidies to fossil fuels
consumed by end-users and subsidies to fossil-fuel inputs to electricity generation,
but do not cover subsidies to petrochemical feedstock. For electricity, subsidy
estimates are based on the difference between end-user prices and the cost of
electricity production, transmission and distribution.
[24] Under the old system, tariffs could not be increased to reflect
fuel prices, sometimes leaving generators with little incentive to increase
generation to meet peak demand and causing frequent blackouts and rolling
outages.
[25] Given that currently no comprehensive database is available in all
EU Member States on energy subsidies, based on a uniform methodology, European
Commission is going to prepare and publish an in-depth study on energy costs
and various subsidies in the energy sector in 2014.
[26] See, for example, the pillars of competitiveness in the Global
Competitiveness Index of the World Energy Forum
[27] With increasing competition and integration of global production
chains offshoring - the decision by European manufacturing firms to move their
production to locations abroad – has gained momentum and attention. The
European Competitiveness Report 2012  refers to data from the European
Manufacturing Survey  for two periods - mid-2004 to mid-2006 and 2007 to
mid-2009 – covering firms from four industrial sectors  and showing that cost
reduction is the dominant motive for relocating production activities abroad,
with factors such as vicinity to customers and expansion of markets the next
most important motivation for offshoring.
[28] BCG. 2013. Behind the American Export Surge. 
[29] DG ECFIN. Energy Economic Development in Europe.
[30] Energy Economic Development in Europe, DG
ECFIN.
[31] Energy costs are defined here as the costs of all energy inputs
(oil, petrol, coal, gas, electricity) used for production purposes including
inputs used as feedstock.  
[32] This analysis is based on the WIOD database (national accounts),
whereby manufacturing refers to industrial manufacturing and includes refining.
The analysis includes feedstock.  
[33] Due to data limitations, figures for energy prices and energy
intensity for the years 2010 and 2011 are not available.
[34] This evolution could be explained by a domestic restructuring or
investment of foreign companies in the US. The analysis here does not
differentiate between these factors.
[35] See Appendix 3 of Energy Economic Development in Europe, DG ECFIN.
[36] Results excluding refining
[37] Price levels are nominal and converted in Euro using ECB XR.
Price indices are in real terms (deflated) and calculated in national
currencies (IEA methodology) 

4.   Future high energy prices in the EU: macroeconomic consequences

The aim of the present chapter is to
evaluate the macroeconomic and sectoral consequences of an increase in
electricity and gas prices in the EU if such increases do not take place in non
EU countries. 
The approach is to quantify stylized
scenarios in which hypothetical causes drive divergence of electricity/gas
prices in the EU relatively to the non-EU world. By no means are such
hypothetical causes related to concrete policies in the EU. The purpose of the
study is purely analytical. 
The Reference scenario projection of PRIMEs
2013[1] which mirrors adopted
policies in the EU and in the Member-States assumes full achievement of EU
objectives (2020 policy package), implementation of current legislation
including the Energy Efficiency Directive and full implementation of the ETS
Directive. In this policy context the Reference scenario projects increasing
electricity prices in the EU until 2020 relative to 2010 levels and full
stabilization of prices after 2020. The Reference scenario also projects
average prices of gas imported in the EU to increase and remain at high levels,
which contrasts with the recent gas price drop in the North American markets. In
addition, persisting subsidization in several non-OECD countries and in the
emerging economies explain low energy prices experienced in the domestic
markets of those countries, as reported by the World Energy Outlook of the IEA
(2012). Therefore, the Reference scenario projects price divergence of
electricity and gas prices between the EU and the USA and between the EU and
the emerging markets for different reasons.
Obviously it is worth to explore the
macroeconomic and sectoral consequences on the EU economy of such a persisting
price differential. The adopted approach preferred to build the analysis
starting from the existing Reference (2013) scenario and assume further
increases in the price differential for electricity and gas over a medium-term
horizon. To quantify these consequences using a model it is necessary to assume
which are the drivers of such an increasing price differential because
depending on the driver the macroeconomic effects can be slightly different.
For this purpose, different scenario variants have been conceived which lead to
similar price differentials but differ in the assumed hypothetical causes. 
For the assessment of impacts, we start
from a quantification of a reference macroeconomic and sectoral projection of
the world economy using the GEM-E3 model, split in many countries/regions including
the individual EU28 member states. A short description of GEM-E3 is available
in Annex 6. The reference
projection includes all assumptions made for constructing the Reference[2] 2013 energy and
transport projection and mirrors the specific energy, transport and
environmental projections of Reference 2013. The geographic coverage of GEM-E3
is global whereas the scope of the Reference 2013 energy/transport projection
is only European. So it was necessary to include assumptions about growth,
energy and emissions for the non-EU world regions. For this purpose we have
relied upon IEA and Prometheus model projections which has been also used to
carry out projections for the world economy and energy for the purpose of
projecting fossil fuel prices to the future considered as inputs to the
Reference 2013 energy scenario. 
To study the impacts of electricity and gas
price increases in the EU we quantify alternative scenarios using GEM-E3 which
include the price increases and we compare projections against the reference
scenario from which we draw conclusions. As GEM-E3 is a fully comprehensive and
global equilibrium model, we need to specify the cause or the driver of
electricity and gas price increases. For this purpose we have quantified
several variants of the price increase scenario in which we vary the
assumptions about the driver of price change. We provide more details below.
As a computable general equilibrium model
GEM-E3 cannot produce forecasts as it requires exogenously assumed
productivity, population and technology progress trends. As usually done for
such models, a reference projection is produced by dynamically calibrating
model-based projections to a pre-defined (assumed) trajectory of aggregated
figures such as GDP, emissions, current account, consumption over investment
ratios, etc. The dynamic calibration depends on assumed productivity evolution
for which the assumptions usually rely on independent statistical studies on
trends[3].
The model serves to produce a projection with details by institutional sector
and branch of activity ensuring consistent with the assumed growth of
aggregated figures.
As is the case of all such models, GEM-E3
produces powerful results when comparing alternative scenarios to a reference,
and so it evaluates the impacts of the changes mirrored in the alternative
scenarios.
We distinguish between two scenario cases:
firstly we quantify scenarios in which electricity and gas prices increase[4] in the EU and we
distinguish between several drivers of such increases. Secondly we quantify a
scenario in which electricity and gas prices decrease in all non-EU countries
but not in the EU. So in both cases the EU electricity and gas prices increase
relative to non-EU countries; this has consequences on EU production and
consumption cost structure in all sectors and drives crowding out effects on
non-energy activity, weakens foreign competitiveness and reduces the EU GDP.
While the modelling exercise covers the
time period until 2050 in 5-year steps[5],
the focus of this chapter is on developments up to 2020.

4.1.           
Scenario Description

Higher electricity and gas prices in the EU 
For scenario definition purposes, end-user
prices for electricity and gas increase in the EU by a pre-defined percentage
per year relative to the reference scenario levels. The changes in energy
prices relative to the reference are presented in Figure 1. 
It is assumed that a temporary distortion
in the electricity and gas markets drive prices above the reference level in
the short to medium term. This distortion can be attributed to a number of
factors i.e. changes in energy taxation, market power or changes in supply
structure. Each cause has distinct effects on the economy through different
channels.
The price differential relative to
reference reaches its maximum value by 2025, and reduces afterwards reverting
back to reference price levels in the long term. Such drivers of price
differentials can persist in the medium term but it is unlikely to last over
long term because they rely on national policies which are obviously
incompatible with well-functioning integrated global markets. So it is logical
to assume that global market forces will prevail in the long term and the price
differential will tend to decrease over time. The annual rates of price
increases are assumed to be the same in all EU member states. 
Figure 1:
Electricity and Gas price EU28
Figure 2 shows gas
and electricity price differentials in the EU relative to USA prices in the scenario variants that project increasing prices in the EU. In these scenarios the
price differentials are assumed to increase in the medium term and to decrease
in the long term for the reasons explained above. 
Figure 2:
Relative energy prices expressed as ratios of EU over USA prices
 
The different drivers considered[6] as causes of
electricity and gas price rise are the following: 

 Rise of taxation applied on gas and
     electricity assuming application of excise taxes above reference levels;
     two distinct variants are considered regarding the way additional state
     revenues due to the energy tax are recycled back to the economy.
 Increase of profit margins in gas and
     electricity supply resulting from excessive market power
 Increased penetration of renewable energy
     sources at higher generation cost than in the reference. 

These causes drive price increases only in
the EU and not in non-EU countries though different channels.
Scenario B21:
Taxation driving higher electricity and gas prices 
In this scenario an indirect tax is imposed
on end-user electricity and gas prices at levels calculated so as to obtain
exactly the assumed price increases as presented in Figure 1. The additional taxation implies
additional revenues for the state. To maintain public budget unchanged from
reference, it is assumed that the rate of social security contributions of
employers decrease; it is obviously assumed that the state recycles tax
revenues back to the economy in an aim at reducing labour costs. This case is
denoted as B21a.
An alternative assumption about recycling,
which has been quantified for sensitivity analysis purposes, is to transfer
additional state revenues of the energy taxation to households as a lump-sum
transfer, which implies an increase in households’ income. This case is denoted
as B21b.
Scenario B22:
Higher price mark-ups driving higher electricity and gas prices 
In this scenario it assumed that the gas
and electricity supply sectors experience excessive market power allowing
higher profit margins than in reference. In the model this is achieved by
increasing the cost mark-up so as to obtain the predefined electricity and gas
price increases. The cost mark-up generates higher gross operating surplus
which is a capital income. These revenues are distributed to the economic
sectors according to their share of ownership. Roughly 80% of the revenues are
allocated to households as additional income and 20% are allocated back to
firms and are re-invested.
Scenario B24:
Higher price only for electricity driven by generation mix
In this variant only electricity prices
increase relative to the reference assuming that generation costs increase as a
consequence of high penetration of renewable energy sources (RES) in the electricity
generation mix. 
Scenario B23:
Low electricity and gas prices in the non – EU countries 
Price differential can also be due to
causes occurring outside the EU. Cheaper and more abundant resources, or even
subsidization, can drive reduction in electricity and gas prices in non-EU
countries. For the purposes of the analysis it is assumed that the price
reduction does not propagate in the EU. Certain geographical or market
conditions can make this happen in reality. Therefore a scenario is defined
which does not assume indigenous to the EU causes of price differentials bit
instead assumes lower electricity and gas prices in the non-EU world driven by
cheaper resources and further assumes that electricity and gas prices in the EU
remain at reference scenario levels. 
Electricity and gas prices in the non-EU
countries as assumed in this scenario are shown in Figure 3. Gas prices in the non-EU countries
are assumed[7]
to decrease more than electricity prices relative to the reference scenario.
The decrease in prices takes place mainly until 2025 where after prices revert
back to reference scenario levels.
Figure 3:
Electricity and Gas price for non-EU countries
 
Modelling
assumptions
The GEM-E3 model covers the global economy
by distinguishing 46 countries/regions linked through endogenous bilateral
trade flows. The model has been extended so as to include all the non-EU G20
countries in addition to representing the individual EU28 member states.
Activity by sector is split in 22 sectors/products and electricity generation
is split in 10 technology types. The industrial sector resolution covers 9
industrial sectors and has included maximum focus allowed by data availability
on energy-intensive industries[8].

GEM-E3 is an open economy model for the EU
and its current account can change by scenario. In all counterfactual scenarios
quantified with the model it was assumed that the current account of the EU28
as a percentage of GDP will remain unchanged as compared to the reference
scenario. This assumption is necessary to render the different scenarios
comparable to each other. In fact, as the model does not include a mechanism to
readjust exchange rates of countries through financial/monetary mechanisms, it
would not capture adequately the effects of an eventual persisting current
account deficit in a particular region. It would be unrealistic to assume that
in a scenario such a persisting deficit would perpetuate without consequences
on relative exchange rates. Instead of a monetary mechanism the GEM-E3 model
uses relative interest rates as an equivalent balancing instrument. The EU wide
interest rate re-adjusts endogenously in the model so as to keep the current
account as a percentage of GDP unchanged. This is a good proxy of a current
account re-balancing through exchange rate re-adjustment. For example interest
rates may increase when changes of prices in the EU imply pressures towards
current account deficit. From a modelling perspective the EU-wide interest rate
is a closure instrument; alternatively the exchange rate could be an equivalent
closure instrument but since the GTAP[9]
original data are all expressed in dollars, GEM-E3 design has opted for using
interest rates instead of exchange rates for closure purposes.  
For the specification of the alternative
scenarios we have made explicit assumptions on the causes of higher gas and
electricity prices in the EU countries as mentioned in the previous section.
Reference
scenario
Basic
Assumptions
The GEM-E3 reference scenario is consistent
with the PRIMES 2013 reference scenario for the EU. The growth and activity
projections by sector and by EU Member-State are identical to the growth
assumptions driving energy projections in the PRIMES 2013 reference scenario
and the energy-related (consumption, electricity generation mix, prices)
projections using the GEM-E3 model have been calibrated so as to be very close
to energy projections of PRIMES 2013 reference scenario. As GEM-E3 is a global
model, energy projections by PROMETHEUS model have to be used to calibrate
GEM-E3 energy-related projections for the non-EU countries. For this purpose
the PROMETHEUS 2013 reference scenario has been retained which is roughly
consistent with the IEA World Energy Outlook New Policies scenario of 2012 and
has also served to project world fossil fuel prices for the inputs of PRIMES
2013 reference scenario. Thus, the degree of consistency achieved between
macroeconomic and fossil fuel price projections as assumed for the reference
2013 scenario is also fully ensured in the current GEM-E3 reference scenario.
As PROMETHEUS has limited geographic resolution, the disaggregation of
projections by country had to be complemented by using additional sources. For
this purpose a 2012 MIT outlook[10]
has been chosen because of the sufficient level of detail and also because the
projections are roughly similar to IEA projections. Labour force and
unemployment rate projections have been based on the Ageing report 2012 of
DG-ECFIN for the EU member states and on the ILO for non EU countries.
International fossil fuel prices are based on the PROMETHEUS 2013 reference
projection. Figure 4 presents
the trajectory for average fossil fuel prices in EU imports.
Figure 4:
International fossil fuel prices in the Reference GEM-E3 scenario (2010 index)
Note:
Fossil fuel prices are average import prices to the EU, not world average.
The international fossil fuels prices have
been projected based on the PROMETHEUS (stochastic world energy model) model
reference scenario for 2013. 
Oil prices increase continuously but the
pace of price rise is slow due to high resource base, apart from uncertain (and
temporary) effects of production capacity pressures in relation to demand
evolution. 
In the short term, high oil prices reflect
the failure of productive capacity to grow in line with demand (fuelled by
economic recovery and persistent growth in emerging regions). 
The situation eases somewhat around 2020
before seeing declining global Reserves to Production ratios from 2030 onwards
and result in a resumption of upward trends. For 2035 oil prices projected by
PROMETHEUS are broadly in agreement with IEA-WEO 2011 New Policies. 
Short term projections of natural gas
prices (average prices of EU imports) show high increases owing to increasing
demand from Asia (particularly Japan after Fukushima and China because of
demand growth) which more than counterbalance reduced import demand in North
America following shale gas exploitation. Asian gas import prices are mainly
driving European LNG gas import prices in the short term while Russian gas
prices for exports to the EU are mainly indexed to oil prices. 
In the longer term the gas price pace
diverts from the upward trend of the oil price, a major break with past price behaviour,
due to the very large additional and currently unexploited resources including
unconventional gas that is assumed to enter the global market in the decade
2020-2030 also in new regions, such as China, in addition to further growth in
North America. As a consequence, natural gas prices tend to stabilize at a
level that nonetheless is still high enough to ensure economic viability of
unconventional gas projects. 
China enters the
global market for coal in 2008 and is assumed to remain a global player
therefore causing coal prices to remain at high levels throughout the
projection period. Coal prices increase at a rather slow pace in the 2025-2040
period due mostly to competition with gas in the electricity generation sector.
In the longer term coal prices stand at levels that are above recent peaks
(e.g. 2008).This is due to consistent demand growth in regions that undertake
only limited GHG abatement policies after 2020 under reference case
assumptions. 
Overview of the GEM-E3 Reference
scenario
Over the 2015-2050 time period the EU28 GDP
is projected to grow annually by 1.5% on average. This rate is lower than the
average world GDP growth rate which is 2.6% for the same time period. Table 1 presents the projection of GDP for
the EU and a decomposition of GDP in large aggregated components. The
projection is consistent with Ageing Report 2012 projection in the long term
and with DG ECFIN short term projections 9as available in early 2013).
In 2010 the openness index[11] (trade to
GDP ratio) of the EU economy is close to 30% which is assumed to be maintained
until 2050, a trend which implies that exposure of the EU economy to foreign
competition will increase in the long term. The reference projection assumes
that the EU maintains a trade surplus over the projection period which is
slightly below 1% of GDP.
The main trading partners of EU are the USA and China for exports[12]
and the USA, China and Russia for imports[13].
The EU has currently a trade surplus in services, intermediate goods and
equipment goods but a trade deficit in energy goods, metals and consumer goods.
The reference scenario projects trade surplus to be maintained and even
reinforced in services, to be maintained by weaken over time in intermediate
goods but to gradually revert to a deficit in equipment goods. The projection
involves continuation of trade deficits in energy and consumer goods. These
trends reflect growth driven by a higher share of services sector and general
reliance on growing contribution of knowledge capital in all sectors allowing
activity to produce more high value-added commodities and less
material-intensive ones. Foreign competition pressure are shown to increasingly
intensify in the equipment and intermediate goods industries as a result of spill
over of technology progress in these sectors towards emerging economies. Trade
deficit of the EU is projected to persist in sectors depending on labour costs,
such as consumer goods industry, and in sectors depending on resources costs,
including intermediate commodities notably ferrous and non-ferrous metals.
Table 1: EU28 GDP growth and components in the
Reference scenario
Source: GEM-E3
Table 2: Rest of the World GDP growth in the
Reference scenario
Source: GEM-E3
Table 3: EU28 Openness indicator
Source: GEM-E3
As mentioned the reference scenario
projects a restructuring of the EU economy towards higher shares of services in
the future and a shift towards higher value added and less resource intensive
production. Energy intensive industries, which are mostly depending on energy
costs, represent a small share in total value added (4% in 2010) which is
projected to further decrease over time. 
Table 4: EU28 trade balance (exports - imports) in
commodities and services
 Trade Balance (in b$ 2010) || 2010 || 2015 || 2020 || 2025 
 Agriculture || -41 || -51 || -61 || -64 
 Energy || -250 || -262 || -277 || -299 
 Intermediate goods || 37 || 133 || 170 || 176 
 Equipment goods || 115 || 65 || -12 || -87 
 Consumer goods || -61 || -118 || -164 || -206 
 Services || 396 || 510 || 629 || 786 
 Total || 198 || 277 || 286 || 307 
 Details about intermediate goods 
 Metals || -48 || -8 || -9 || -19 
 Chemicals || 73 || 139 || 172 || 186 
 Non Metallic Minerals || -6 || -7 || -6 || -8 
 Paper and Pulp || 18 || 10 || 12 || 17 
 Details about equipment goods 
 Electric goods || -154 || -162 || -169 || -176 
 Transport equipment || 102 || 108 || 96 || 99 
 Other equipment goods || 167 || 118 || 62 || -9 
Source: GEM-E3
Table 4 shows a strong increase in the terms
of trade for the services sectors. This result is linked to the on-going
tertiarisation of the EU economy but may also be related to the assumption of a
fixed current account.
Table 5: Average EU electricity price in the
Reference scenario
 Annual growth rates || 2011-2020 || 2021-2030 || 2031-2050 
 Average end-consumer prices || 2.76% || -0.04% || -0.09% 
 Electricity generation costs || 2.40% || -0.17% || -0.19% 
 of which fuel costs || 1.36% || -0.78% || -0.49% 
 Grid and supply costs || 2.35% || 1.01% || 0.57% 
 Taxation and ETS costs || 22.02% || 7.86% || 0.93% 
 Recovery of RES support || 22.57% || -4.70% || -23.45% 
Source: GEM-E3 and PRIMES
The price of electricity is calculated on
the basis of generation costs, the recovery of investment expenditures in grid
infrastructure, the costs of renewable support schemes, the ETS auction
payments and the applicable taxes. In the reference scenario electricity prices
are shown to increase mainly until 2020 as a consequence of rising gas prices,
assumed in the reference scenario context and the increased costs for
renewables.
Figure 5:
Electricity and gas consumer price index projections in the Reference scenario
(based on PRIMES and PROMETHEUS models)
The rise of electricity prices is shown to
stop after 2020. This is driven mainly by the projected decoupling of gas to
oil prices and the modest increase of gas and coal prices after 2020.
Productivity in electricity generation and supply also increases after 2020 as
new power plants are massively committed in the system which embody
technologies with higher efficiency. 
Although the system has increasing needs to
recover capital costs as replacement of old generation capacities increases
after 2020, given the ageing of power plants in the EU, technology progress
allows compensation of higher capital costs by efficiency and unit cost
reduction gains. ETS carbon prices are projected to increase after 2025 and reach
significant levels driven by ETS Directive implementation which provide for a
linear annual decrease of allowances (EUA) at an amount calculated by applying
1.74% on base year emissions. ETS auction payments by electricity generators
are assumed to be reflected onto retail prices. 
Costs of renewable support schemes are
projected to significantly decrease after 2020 as a result of gradually
decreasing feed-in tariff schemes, as renewable development after 2020 is
mainly driven by ETS carbon prices and is facilitated by investment cost
decreases due to learning trends. The drop of renewables cost compensates the
projected increase in costs driven by ETS.
The gap of energy prices between EU and
other countries (mainly with USA, Japan and China) is assumed to remain
throughout the simulation period and to reduce along a relatively low pace of
convergence over time (see Figure 5). The low price countries see
increasing prices in the future but price levels in the long term remain well
below the EU levels. Increasing and diverse energy prices are also projected by
a number of studies including IEA’s WEO (2013). The reason of persisting price
divergence is subsidization in the non-OECD countries. For North America it is
due to emergence of non-conventional hydrocarbons which has allowed for price
drops already before 2010. 

4.2.           
Modelling results

Macroeconomic
impacts of price increase in the EU
Overview of
results
An increase in the prices of gas and
electricity, unilaterally in the EU and non in the non-EU world, affects
economic activity through multiple channels setting in motion substitutions
between production factors, changes in foreign trade, restructuring of
production and demand towards less energy intensive goods and services, etc.
Because electricity and gas cannot be
perfectly substituted by other commodities or services, the increase of their
prices implies higher costs to be borne by end-consumers of energy (firms and
households) and as the resources of the economy are limited, the price rise
implies a crowding out effect affecting expenditures in other goods and
services. For households, the share of energy expenditures to total
expenditures has to increase, given that gas and electricity products are
considered as essential inputs and cannot be perfectly substituted. Thus
purchasing power of income weakens which implies lower demand for non-energy
related goods and services. 
Also because of lack of substitution,
production costs of energy consuming producers of goods and services will see
increased costs (1.2% on average in 2025 above reference). Consequently prices
of domestically produced goods and services have to increase which drives lower
domestic demand both by households and by other production sectors using
domestically produced goods and services as input production factors (demand
for energy intensive products decreases by 1.0% in 2025). 
Although substitutions away from
electricity and gas are difficult, the consumption and production structures
adapt as much as possible to alleviate the cost impacts of price rise and the
economy finds a new equilibrium in capital and labour markets at lower price
clearing levels (return on capital and wage rates) in order to mitigate
downwards pressures stemming from lower domestic demand. So the substitutions
and the market re-adjustments reduce the cost impact of price rises at levels
below cost impacts that would be suggested by the initial share of electricity
and gas in total costs by sector. 
The model results show that at the new
equilibrium, with electricity price increases of 25% and gas price increases of
17% unit cost of total households’ consumption increases moderately by 0.4% on
average in 2025 (driven by 6% increase of unit costs of all energy forms
consumed by households) and average production cost of firms increases by 0.35%
in 2025 while costs increase by 1.5% in energy intensive industries, compared
to reference. Consumer price index increase by 0.59% and GDP deflator by 0.20%
compared to reference in 2025. The cost and price impacts reduce beyond 2025
while electricity and gas price increases diminish by assumption.
Driven by the price rise and the lower
income due to lower demand for labour, the rise of electricity and gas prices
cause private consumption to drop (Table 6). Expenditure for purchasing
non-energy commodities and services also decrease, including for the purchasing
of equipment goods which use electricity or gas. Nevertheless, energy intensity
of households’ consumption reduces compared to reference, by 1.5% approximately
in 2025, but this gain is not sufficient to overcome the effect of price rise
on final consumption.
Table 6: Impacts
on Private Consumption (EU28)
Source: GEM-E3
Production of goods
and services becomes more energy efficient in all sectors, as a result of
electricity and gas price rise: energy intensity decreases by 2.4% (3.5% in
energy intensive production) in 2025 compared to reference but this improvement
is not sufficient to offset overall cost increases. The effects of price rise
on domestic activity and demand exert downward pressures on capital and labour
markets leading to lower capital return rates and lower real wages (-0.1% for
capital costs and -0.87% for labour costs in real terms in 2025, compared to
reference). However, despite cost reductions in using primary production
factors, domestic production sees price increases, except in few high labour
intensive sectors (services). Therefore the increased prices of domestically
produced goods and services moderately impacts foreign competitiveness in these
sectors. Imports tend to increase and exports tend to decrease (Table 7 and Table 8). The
readjustment of interest rates driven by the capital market re-balances the
current account as percentage of GDP but despite this the trade balance
deteriorates as a consequence of electricity and gas price increases. The
structure of exports also changes, shifting in favour of highly priced exported
goods and away from low priced goods (e.g. materials) which is shown as a
slight increase of terms of trade (average price of exports over average price
of imports) compared to the reference. 
Table 7: Impacts on Imports
(EU28)
Source:
GEM-E3
Table 8: Impacts on Exports
(EU28)
Source: GEM-E3
Private consumption decreases and because
of rising EU production costs consumption shifts towards non-European goods,
exports decrease and hence overall domestic production decreases. The decline
in the activity of sectors exerts a downward pressure in the demand for labour
and capital which is partly offset by the substitution effects among production
factors, induced by higher electricity and gas prices. Production shifts
towards more capital and/or labour intensive methods of production because of
substitution. Nevertheless the net effect for both the capital and the labour
market is negative as the potentials for substituting energy with capital
and/or labour are very limited. So the demand reduction effect dominates
leading to lower demand for labour and capital. The downward pressure on
capital and labour markets imply lower equilibrium prices which mitigate but do
not cancel the volume effects.
Table 9: Unemployment Rate (EU28)
Source: GEM-E3
Table 10: Real Average labour cost (EU28)
Source: GEM-E3
Higher unemployment rates (Table 9) along with lower wages and capital
return rates are indicated (Table 10), although the labour and the
capital markets do dispose some degree of flexibility. If gas and electricity price
rise as a result of additional taxation, and assuming that the additional state
revenues are used to reduce labour costs, by decreasing the employer’s
contributions to the social security system, the reduction of the effective
cost of labour has positive influence in the labour market, increasing
employment as compared to other scenarios with higher energy prices (Mark-up,
High RES and Energy tax with
lump-sum transfers to households). 
In the labour intensive sectors, where
human capital is the most important factor of production, unlike the energy
intensive ones, experience some slight gain in competitiveness and an increase
in their demand from trade due to the lower labour costs. In these sectors,
notably some services sectors, exports increase on average by 0.4% over the
period 2015-2050 compared to the reference.
The depression of demand and the reduction
of rates of return on capital go together with slowing down of investments
which is dynamically captured in the model. Investment expenditures reduce (Table 11), as demand
growth expectations reduce. Lower investment implies lower demand for equipment
goods, services and construction which are used to build investment; this adds
to the depression of total domestic demand. In addition, the reduction of the
rate of return on capital, makes investment in the EU less attractive and
induces re-orientation of global capital flows which exerts pressures on the
current account towards a deficit. Thus lending becomes more expensive and also
savings increase which further implies lower consumption. If mark-ups in
electricity and gas supply are the causes of electricity and gas price
increases capital income increases and these extra revenues are recycled back
in the economy acting in favour of investment; thus the increased availability
of funding favours overall investment in the economy and despite the depression
of demand investment slightly increases dynamically over time (0.001% over the
period 2015-2050 compared to the reference) helping to attenuate quickly the
adverse effects of the price rise on domestic activity. 
Table 11: Impacts on Investment (EU28)
Source: GEM-E3
The model results confirm that all high
energy prices scenarios imply lower EU GDP relative to the reference case (Table 12). Depending on the causes that drive
the increase in energy prices the negative impact on GDP is different in
magnitude and on each GDP component.
Table 12: Impacts on GDP (EU28)
Source: GEM-E3
The impact of loss of competitiveness on
trade is significant for energy intensive products. The adverse effects are far
more pronounced on energy intensive products which are more exposed to foreign
trade, primarily on ferrous and non-ferrous metals, but also on chemicals.
Impacts are lower on non-metallic minerals and on paper which are less exposed
to trade and are more related to domestic demand as trade implies high
transportation costs.
Table 13: Impacts on trade of energy intensive
products in taxation case B21a (EU28)
Source: GEM-E3
The consequences of gas and electricity
price rise is thus more severe for the energy intensive sectors whose
production costs rely heavily on energy inputs. Driven by depressed domestic
demand, lower exports and higher imports, domestic production of energy
intensive industries is significantly reduced in all scenarios (Table 15, Table 14 and Table 16). As a result, trade surplus of the
EU in the energy intensive industries decreases over the period 2015-2050.
Table 14: Impacts on production of energy-intensive
industries (EU28)
Source: GEM-E3
Table 15: Impacts on imports of energy-intensive
products (EU28)
Source: GEM-E3
If price changes are perceived by firms as
a permanent rather than a temporary shock the effects are higher on the
European economy. The model-based simulations have assumed that price changes
are permanent but their intensity changes over time as the price increases tend
to vanish in the long term. So the model captures dynamic re-adjustment of the
EU economy and shows some degree of attenuation of adverse effects in the long
term. 
Table 16: Impacts on exports of energy-intensive
products (EU28)
Source: GEM-E3
Nonetheless the model does not capture
readjustment effects stemming from changes in R&D and induced productivity.
The change in the relative prices of factors of production creates incentives
for the firms to invest more funds on R&D to improve energy efficient
methods of production. Technological progress creates the potential for a
rebound effect in the European competitiveness, compensating for the increased
price of energy inputs. Nonetheless, the induced technological change cannot
fully offset the effect of higher prices on unit production costs as energy (and
in particular electricity and gas) is an essential input in production.
Negative effects will be mitigated but will still persist although the long run
resilience of the economy to energy price increases will be higher. Despite not
fully capturing the induced technological progress, the model results show
significant improvement of energy intensity and reduction in emissions.
In conclusion the modelling indicates that 17%
to 25% higher electricity and gas prices will reduce the European GDP growth by
0.2% - 0.45%, with the magnitude being dependent on the trade openness of the
sectors who contribute the most to the value added of the economy and the form
of revenue use, and it is expected that this reduction will be accompanied by a
transformation towards higher shares of services and less energy-dependent
goods.
Scenarios
B21a and B21b: Taxation of electricity and gas
These scenarios explore the impacts of
rising taxation of electricity and gas as a possible cause of electricity and
gas price rise. As described in the previous section, domestic rise of
electricity and gas prices in the EU asymmetrically has negative effects on
GDP, domestic activity and private income due to crowding out effects and
through the weakening of foreign competition. The intensity of impacts assuming
taxation as the cause of price rise is similar to findings of simulation of
impacts by other possible causes. But it is worth mentioning that the indirect
effects of how taxation revenues are recycled aback to the economy constitute an
important consideration as the results show that the recycling scheme is not at
all neutral regarding the impacts on the economy. Two different recycling
schemes have been examined: 
i) The
revenues are used to reduce social security contributions of employers and thus
help reducing labour cost (B21a). 
ii)                 
The revenues from increased energy taxation are
directed to households so as to increase their income and sustain private
consumption (B21b)
The negative effects on GDP are
significantly more pronounced in the second case. Consumption changes resulting
from an increase in the disposable income of households fail to compensate for
the competitiveness loss in EU due to higher electricity and gas prices. The
increased costs of production undermine the competitiveness of European sectors
and the demand for EU products from abroad falls by 0.28% in 2025 (compared to
the reference).  Although public transfers support households’ income the
incurred loss in competitiveness drives the EU GDP down (-0.44% cumulatively) as
exports deteriorate (-0.23% cumulatively over the period 2015-2050 as compared
to the reference). 
Additional income of households is spent on
both domestic and imported goods. Thus part of the additional income translates
into demand for goods produced by non-EU countries. In this scenario imports
are sustained from higher household demand for imported goods as preference
shifts over relatively cheaper imported goods (-0.03% cumulatively over the
period 2015-2050). At a sectoral level, the increase in total production cost
of energy intensive sectors (-1.5% on average in 2025 compared to the
reference) is higher among the two taxation cases and this implies stronger
adverse effects on production and exports (they reduce by 2.0% and 3.5%
respectively in 2025 in the second taxation case). 
Recycling tax revenues so as to reduce
social security contribution rates implies lower labour costs and this partly
offsets cost impacts of electricity and gas prices on production costs and
mitigates price increasing trends in the economy. Thus competitiveness losses
are also alleviated and so depressive effects on domestic demand are mitigated,
compared to the alternative taxation case. The decrease in the cost of labour
sustains demand for labour and as a consequence the reduction in wage income is
mitigated, hence the effect of higher energy prices on private consumption
(-0.3% in 2025 compared to the reference) is lower than in the alternative
taxation case. 
The beneficial effects of recycling
taxation revenues towards reducing labour costs hold true also for
energy-intensive industries although they are not labour intensive. This
finding is attributed less to direct consequences on competitiveness but rather
to general economic multiplier effects because the labour cost reductions has
overall demand sustaining effects in the economy hence positively affecting
domestic demand addressed to energy-intensive industries. In addition, negative
effects of taxation cases on investment and construction are also mitigated in case
of recycling in favour of reducing labour costs which also favours demand
addressed to energy-intensive industries.
Taxing electricity and gas and recycling
revenues to households has found to exert the highest, among all cases,
negative impact on energy intensive sectors. In cumulative terms, the
mitigation of negative effects on production due to recycling taxation revenues
in favour of labour costs is 0.30 percentage points (annual change) for metal
products and 0.20 percentage points for the rest of energy-intensive products.
Table 17: Impacts on production by sector in the
two taxation cases (EU28)
Source: GEM-E3
Labour cost
reductions result in net competitiveness gains for labour intensive industries
(e.g. services) and as a consequence exports increase and imports decrease,
despite the increase of electricity and gas prices. The gains from trade are,
however, not sufficient to drive positive effects on domestic production of the
services sector, because of lower domestic demand.  The impacts on domestic
activity are mitigated for all sectors in the recycling case towards labour
costs (Table 17). 
The overall effect on the trade balance of
non-energy intensive sectors is found to be positive. The loss of exports of
energy-intensive products is partly compensated by higher exports of services
and other low energy-intensive products. These sectors benefit from cost
reductions due to labour and capital unit costs which as mentioned above
decrease in the taxation scenarios as a result of the overall depression of
activity (Table 18).
Table 18: Trade balance (EU28)
The signs stand for deficit (-) or surplus (+)
Source: GEM-E3 
Scenario
B22: Higher mark-ups on electricity and gas costs 
In scenario B22 higher costs mark-up in the
electricity and gas prices, assumed to be the cause of electricity and gas
price rises, imply higher operating surpluses in the electricity and gas
sectors. Households and firms collect higher dividends and funding of
investment is potentially higher although for individuals the additional income
is also used for consumption purposes. Consequently, investment is found to be
less affected in this scenario than in any other of the EU price increase
scenarios. This result has to be considered with caution because it is due to
modelling assumptions reflecting the general equilibrium approach of the model.
Market failures or non-optimal capital flows seen in reality as driving less
efficient outcomes of mark-up based revenues; these are not captured by the
model.
Sustaining investment has dynamic impacts
in the economy which are captured by the model. Although the negative effects
on GDP are of the same order of magnitude as in the other EU price rising
scenarios, the long term effects on GDP are lower: the pace of vanishing GDP
impacts is much faster than in any other scenario.
Nonetheless, the mark-up scenario shows
higher negative effects on GDP than the labour cost recycling taxation case
during the period of peaking price differential for electricity and gas.
Scenario B24:
Higher price only for electricity driven by generation mix 
For scenario B24 it is assumed that
non-optimal investment in expensive renewables takes place in electricity
generation and drives higher electricity prices (9% above reference in 2025),
as capacity expansion hence generation mix deviates from optimality as
simulated in the context of the reference scenario. It is also assumed that in
order to finance the additional investment requirements in electricity sector,
funds are drawn from households which implies that income is reduced and
private consumption has also to decrease. The additional investment expenditure
in electricity sector, although accounted for in total investment, is not
driving additional productive capacity as it is assumed that capacity remains
unchanged and that only unit cost of investment in electricity sector
increases. Obviously this assumption corresponds to loss of efficiency in the
economy and lower demand by households. In addition, the high capital
requirements in electricity sector stress capital markets and lead to higher
average cost of capital which has adverse effects on costs in other sectors and
as a consequence activity decreases, economy-wide, also driven by lower private
consumption. Gas prices are assumed not to change relative to reference. So
average energy costs in industry is less affected than in other scenarios.
The increase in investment costs due to
capacity expansion towards inefficient renewable energy forms implies higher
demand for equipment goods used to build the renewables. This effect is however
small and fails to counteract the effects of dropping demand driven by crowding
out effects to the detriment of private consumption.
Compared to taxation scenarios, B24 shows
significantly higher negative impacts on GDP and on production by sector but
also significantly lower negative effects on energy-intensive industry. The
latter effect is due to the energy price costs which increase in B24 much less
than in the taxation scenarios.
Scenario B23:
Low electricity and gas prices in the non – EU countries 
The B23 scenario differs from the other
because it is assumed that electricity and gas prices reduce in the non-EU
countries and not in the EU, which is quite different from assuming price rise
indigenously in the EU. 
In the B23 scenario the non-EU countries
collect benefits from getting higher access to low cost energy resources and to
more productive extraction of gas; as electricity and gas prices reduce in
these countries, economic growth is boosted and demand addressed also to the EU
increases. In addition, product prices in the non-EU countries decrease and so
EU can import goods at lower prices relative to the reference. The
non-propagation of energy price decreases in the EU implies competitiveness
losses for the European goods and services which implies trends towards EU
imports and lower exports by the EU. This exerts negative effects on the EU
economy. So, in the B23 scenario the EU is affected by two mainly counteracting
mechanisms: higher demand from abroad and lower prices of the goods sold in the
EU which have positive effects on demand and deteriorated trade competitiveness
which has negative effects on activity.
The additional growth in non EU countries
driven by lower energy costs is found to amount to 0.6% for GDP and 0.8% for
consumption, cumulatively over the period 2015-2050 compared to the reference
case. This increase sustains the demand primarily for non-energy intensive
European goods and services hence exports of EU increase (0.6% over the period
2015-2050 as compared to the reference). In addition EU is benefitting from
cheaper imports and private consumption increases marginally by 0.01% over the
period 2015-2050 compared to reference.
The decrease in energy costs induce
competitiveness gains for energy intensive industries located outside the EU
and increase imports’ penetration in the European market. Imports by the EU
increase by 2.0% over the period 2015-2050. Nevertheless the recorded reduction
in the production of the European energy intensive industries is lower than in
other scenario examined (-0.6% over the period 2015-2050) due to higher global
demand. Changes in domestic (EU) demand induced by negative income effect (i.e.
the increase in prices reduces real income thus demand) are moderated since the
cost of living does not increase. Therefore changes in production in the EU
(for energy intensive industries) are driven primarily by changes in foreign
trade. Trade balance in the EU worsens as a consequence of the shift towards
the consumption of cheaper imported products and GDP remains stable (0.02%) as
compared to the reference. 
Table 19: Macroeconomic effects on the EU
of asymmetrically lower prices in non-EU world
Source: GEM-E3

4.3.           
Chapter conclusions

The aim of the present chapter has been to
quantify economic impacts on the EU economy of future price differentials for
electricity and gas between the EU and the non-EU world. From a modelling
perspective, scenarios have been quantified using the GEM-E3 global general
equilibrium model, in which electricity and gas price rise in the EU has been
hypothetically driven by taxation and other possible causes. A different
scenario has been also quantified in which electricity and gas price reductions
take place in the non-EU world and do not propagate to the EU. These are
obviously stylized scenario cases. The results are compared to a reference
scenario, also quantified using GEM-E3, which mirrors the recently published
Reference 2013 scenario of the European Commission.
The model results clearly show that a
strong asymmetric rise of electricity and gas prices in the EU would
have adverse effects on the economy, depresses domestic demand, activity
and investment. The energy intensive industries could suffer from loss of
competitiveness due to energy prices and see diminishing shares in global
markets. Adjustments in capital and labour markets towards lower capital and labour
prices driven by lower demand would not appear to offset competitiveness
losses. Substitutions towards less energy intensive production and consumption
patterns, as far as captured by the model, are also unable to fully alleviate
consequences. It is worth considering more closely the causes of energy price
rises because they have different economic effects. Raising taxation of
electricity and gas but using tax revenues to reduce labour costs, through
social security accounting, was found to be the most beneficial among the cases
examined for GDP and private consumption, but also for competitiveness.
However, despite labour cost reductions the negative effects in the EU economy
remain. Recycling taxation revenues as lump-sum transfers to households was
found to be less beneficial for GDP, welfare and sectoral activity than
reducing labour costs. This is a finding which is shared by a vast literature
on possible double dividend analysis (for environment and employment).
Electricity and gas price rises driven by
market power in electricity and gas supply was found to exert negative effects
on the economy in the medium term but to present a different dynamic pattern
showing rapid deceleration of negative impacts. This is due to the dynamics of
investment which is shown to sustain in this scenario due to higher returns on
capital. Nonetheless the economic effects remain detrimental to private
consumption and welfare.
A different case of price differential is
when prices of electricity and gas decrease in the non-EU world but not in the
EU. Assuming that productivity and cheap resources drive the price drop, the
non-EU world benefits from lower costs allowing for higher growth. Hence,
global demand increases in this scenario and the EU collects benefits from
higher demand addressed also to the EU and from lower cost imports, the latter
being beneficial to domestic private consumption. The EU still bears negative
effects on activity stemming from the undermining of competitiveness, but the
overall the effects are neutral or even slightly positive on the EU, as
benefits collected from abroad almost offset impacts of competitiveness losses.
So this case fully contrasts the cases where electricity and gas price
differentials are due to indigenous reasons in the EU. 
Details are provided by sector of activity.
The results confirm the vulnerability of energy intensive industries in
particular those that are exposed to foreign competition, such as metals and
chemicals. In all scenarios, activity in these industries is significantly more
reduced than in other industries. It was found that some of the low
energy-intensive sectors, such as the services, may even profit from capital
and labour cost decreases in some of the scenarios.

Annex 1. Electricity and gas price evolution:
results by Member State

As part of the data-collection exercise
for this report, Member States provided the Commission with data on energy
prices for electricity and natural gas for median industrial and domestic
consumption bands in two years, 2008 and 2012. In this data (referred to as Metadata
in the report), prices were broken down first into the categories of energy and
supply costs, network costs and taxes and levies. These sub-headings were then
broken down further into individual components: for example, network costs were
divided into the cost of transmission and the cost of distribution; taxes and
levies were decomposed into excise taxes, VAT and other special levies.
This Annex is based on the results from
the Metadata analysis, intended to improve understanding of the exact
composition of each price component (energy and supply, network, taxes and
levies).  Throughout the report the Metadata was used only in cases where a
comparable – though not as disaggregated – data is not available from Eurostat,
namely in the case of breakdown by price component of retail prices for natural
gas for households and industrial users. 
The level of detail in which Member
States reported their energy prices in the Metadata varied
significantly. In some cases, network costs were reported as a single,
undifferentiated item; in others, they were broken down into as many as five
separate components. The same is true of energy and supply costs and taxes and
levies.
There were also significant differences
in the ways in which Member States categorised certain kinds of charges. The
heading energy and supply costs, for example, does not always designate the
same set of charges and activities in each country. It is important to bear
these inconsistencies in mind when considering the data, as they complicate the
task of comparing the breakdown of Member States' prices. To take the most
salient example, the part of the electricity bill relating to support for
renewable energy generation is counted variously as an energy and supply cost
(Belgium, United Kingdom, Spain), as a part of network charges (Czech Republic,
Slovakia, Denmark) or most commonly as a levy (Austria, Germany, various other
Member States). 
 EU ||   For the EU as a whole, between 2008 and 2012 retail electricity prices rose for both industrial and domestic consumers, by 17.28% and 12.87% respectively. For domestic consumers, this equated to a rise of 2.98c per kWh, of which 1.76c were attributable to taxes (including VAT). Looking at the HEPI weighted average for capital cities of 15 EU Member States[14], energy and supply costs rose by 3.39% and network costs by 32.33%. Gas prices also rose across the EU, although to a lesser extent than electricity prices – domestic prices rose by 13.67% and industrial ones by 5%. The main driver in this change for domestic consumers was non-tax costs, although proportionally the greatest change was in taxes and levies. 
 AT || Between 2008 and 2012, Eurostat data shows that average Austrian electricity prices for domestic users rose by 14.2% to a level slightly above the EU average. This was mainly due to significant increases in energy and supply costs and network costs, although taxes and levies were the component which rose most sharply. Domestic gas prices also rose by over 23% to a level slightly over the EU average. For industry, the electricity price rises were more moderate, increases in the grid tariff and taxes (charges such as the community levy and renewables surcharge) tempered by a decrease in energy and supply costs. 
 BE || Domestic electricity prices in Belgium were above the EU average in 2012. There was an  increase of 3.3% from 2008 to 2012, of which a major part was due to rising distribution charges. For industrial consumers, electricity prices were consistently below EU averages but grew by 15.2%, again driven by increased distribution charges. Industrial gas prices fell by 10.7% in the same period thanks to decreasing energy and supply costs. 
 BG || Bulgarian gas prices rose sharply between 2008 and 2012, by 42.2% for domestic consumers and by 49.2% for industrial users. The main driver behind these rises were energy and supply costs, although VAT rises and (for industry) distribution costs were also significant factors. Electricity prices also rose, although not at the same rate, with the main driver being energy and supply costs, including the additional price for green energy. All electricity price components increased at roughly a similar rate (14-17%). 
 CY || In Cyprus, domestic electricity prices rose by 42.6% from 2008 to 2012, to levels well above the EU average. Industrial prices were volatile, rising 31.66% to levels almost double the EU average. The greatest percentage of the increase was in generation and supply costs, but the rise in VAT was also an important factor. 
 CZ || Eurostat databases show that Czech electricity prices for all users decreased slightly between 2008 and 2012. Increases in network costs, among which is counted the charge related to support for renewable generation and CHP, were offset by declining production supply costs. In the same period, domestic gas prices rose steeply (by nearly 25%), the changes driven by increases in energy and supply costs, while for industrial users this component actually decreased, leading to a fall of 13.4%. 
 DE || Industrial and domestic electricity prices in Germany each rose by over 20% from 2008 to 2012, driven in particular by an increase in taxes and levies. The EEG-Levy (financing renewable generation) and an increase in VAT were each important factors in the rise in this component. In parallel, gas prices decreased, falling in particular for domestic users by nearly 15% as the cost of energy and supply reduced. 
 DK || Electricity prices were among the highest in Europe for Danish users between 2008-2012, despite a significant fall in energy and supply costs. The single largest part of Denmark's electricity price was composed of the country's electricity tax, which in 2012 represented over 31% of the price paid by domestic users and a higher proportion for industry. The Increasing network costs also played a role in this, in particular the "Public Service Obligation", primarily financing support to RES[15]. Gas prices also rose in the same period, by 23.58% for industrial users, from cent EUR 3.86 / kWh to cent EUR 4.77 / kWh. 
 EE || Estonia's electricity prices remained below EU averages between 2008 and 2012, but proportionally saw some of the steepest rises, driven in particular by increases in taxes and levies, including charges introduced by the country's Renewable Energy Act. Gas prices  also rose, by over 35% for industrial consumers, as distribution and transmission costs went up and VAT was increased. 
 ES || Domestic electricity prices rose steeply in Spain, from a level slightly below the EU average in 2008 to one above it in 2012. This increase of 46.1% was attributable in particular to increased distribution costs (which includes other, non-network costs and charges such as RES and tariff deficit financing), increased VAT and the increase in the special regime premium for RES and CHP generation. The pattern was the same, although increases less pronounced, for industrial users. Spanish domestic gas prices also rose by 39.5%, due to increases in VAT and network costs. 
 FI || Increases in Finnish electricity prices from 2008 to 2012, of 22.5% for domestic and 11.3% for industrial consumers were driven in particular by growing network costs and an increase in taxes and levies. Industrial gas prices in this period increased by 42.6% to a level  above the EU average. The major contributor to this increase was a rise in taxes and levies (in particular carbon dioxide tax) and a rise in energy and supply costs. 
 FR || In France, electricity price increases of around 27% between 2008 and 2012 were driven primarily by increases in all individual components. Increases in network costs were a significant factor, in particular for industry. Gas prices rose sharply for domestic consumers, by 17.99%, although taxes were not the major factor in this rise. 
 GR || Greek electricity prices rose steeply for both industrial and domestic consumers (29% and 37.3% respectively), although in both cases they remained below the EU average. In part these increases can be explained by the introduction of non-recoverable tax rates where previously there had been none. In 2012, gas prices in Greece were comfortably above the EU average for both domestic and industrial consumers. 
 HR || Although below the EU average, Croatia's domestic electricity prices rose by 16.9% between 2008 and 2012. Industrial price rises were more modest, in part due to a decrease in the network costs paid by industry. The country's gas prices rose sharply, by 70.4% and 104.6% for domestic and industrial consumers respectively. A VAT increase was one factor here, but the main cause was a major rise in the natural gas shipping rate. 
 HU || For Hungarian industrial consumers, electricity prices slightly decreased between 2008 and 2012, mainly due to decrease in energy supply costs. Rises for domestic consumers were mostly in line with the overall consumer price index, resulting from a fall in wholesale prices offset by rising transmission costs and increased VAT. Gas prices for both industry and domestic use fell, due to decreased supply costs. 
 IE || Gas prices rose in Ireland by 3.4% for domestic and 6.2% for industrial use, driven in each instance by an increase in taxes and levies. In both instances, Irish prices remained below EU averages. Electricity prices fell for industry by 1.8% thanks to a fall in energy and supply costs, while domestic prices rose by 9.1%. Tax increases, specifically the introduction of an energy tax, were a significant factor in rises for each sector. 
 IT || Electricity price rises in Italy were primarily driven by increases in taxes and levies, which for industrial users more than doubled and for domestic consumers increased by over 42%. Gas prices fell for industrial consumers but domestic prices rose by 34.4%. 
 LT || Lithuanian electricity prices rose by 46.6% for domestic and 39.8% for industrial uses, the largest portion of the increases owing to the rising energy price. For gas, there was a major rise in domestic bills of nearly 60%. Rising gas supply prices affected domestic consumers most significantly, with the increase in distribution costs also having a significant impact on all users. 
 LU || The most significant rises in Luxembourg's energy costs were for gas, where industrial prices rose by 25.4% and domestic ones by 15.6%. Major increases in wholesale gas prices drove this increase; distribution and transport tariffs decreased, and the tax component of gas bills fell or remained constant. Over the 2008-2012 time period, electricity prices increased only slightly, at just over 6% domestically and 3.5% for industry, thanks to a fall in the price of wholesale electricity. 
 LV || Although below EU averages, Latvia's electricity prices increased significantly (by 36.5% for domestic and 43% for industrial use). Rising charges to support renewable energy played a significant role in these increases, as did an increase in VAT. Distribution and transmission tariffs also went up. Gas prices rose by 12% for domestic consumers, affected again by rises in VAT. 
 MT || Malta's industry faced electricity prices above the EU average between 2008 and 2012. Industrial and domestic prices grew at a similar rate (11.2% to 10.7%). The rises were attributable to increases in the single largest component in bills, energy and supply costs. 
 NL || Energy and supply costs for electricity fell in the Netherlands, but increases in network (in particular transmission) costs of nearly 20% for domestic users and 13.4% for industry plus rising taxes and levies meant that there were price increases of 5.7% and 6% for households and industry respectively. Gas prices for industry fell by 0.9%, although they rose for households by 11.5%, due in part to a significant increase in the cost of transmission. 
 PL || Domestic consumers in Poland experienced electricity price increases of 18%, driven by energy and supply cost increases of 30% as well as rising cost of transmission and distribution.  For industry, price rises were more modest, and the burden of network costs and taxes and levies actually decreased. Gas prices rose at similar rates for industry and household, by 11.8% and 12.4% respectively, with the main factor being the gas and supply costs. 
 PT || In Portugal, taxes and levies rose on domestic electricity consumption rose by over 107%, the most significant factor in an overall price increase of 35.3%. The major increase was in VAT, followed by increases in capacity payments and old stranded generation costs. For industry, transmission and distribution costs were the major contributor to a price rise of 48.9%. Domestic gas prices increased by 35.6%; again, the main driver of this increase was the rise VAT. 
 RO || Romania's electricity prices bucked the EU trend by decreasing over the 2008-2012 period, as both energy and supply and network costs fell. Domestic prices decreased by 2.5% and industrial ones by 7.2%. Gas prices, too, fell significantly; 18.5% for domestic consumers and 1.8% for industry, due to falling energy and supply costs. 
 SE || Electricity prices rose only very slightly (0.5%) for Swedish industry, but by a more significant margin (19.3%) for domestic users. Although energy and supply costs went down, significant increases in network costs (of over 43%) and taxes and levies ensured a net price rise. Gas prices also rose, by 24.8% for households, a decrease in energy and supply costs offset by in particular by increased taxes. 
 SI || Electricity prices for Slovenian industry fell by 4.3% between 2008 and 2012, thanks to the falling wholesale electricity price and reduced transmission and distribution costs. These decreases were partially counterbalanced by an increase in taxes and levies, in particular the excise tax on electricity consumption. Increases in network taxes and VAT pushed gas prices for industry up by 20.8%. Domestic electricity prices increased by 33.4% overall, with every individual component increasing. Rising energy and supply costs were the main price component but the cost of network distribution also contributed. 
 SK || In Slovakia, there were modest increases in the prices industry paid for energy, of 0.5% for electricity and 6% for gas. Household users faced greater rises, totalling 12.8% for electricity and 10.5% for gas. For electricity, network costs and taxes and levies accounted for a greater proportion of the rise than did energy and supply costs. For industry, the cost of charges related to the country's Renewable Energy Act in particular increased more than fourfold, pushing up network costs. 
 UK || In the UK, gas prices for domestic consumers rose steeply between 2008 and 2012, by around 20.9%. This was mainly due to increased wholesale costs. In the same period, gas network costs in the UK decreased. For industry, there was a more modest rise of 6%, although in each case the UK remained below the EU average. For domestic electricity users, a price increase of 11.4% was driven by rising energy and supply costs; network costs actually decreased by 21.4% in this period. Under the heading of energy and price costs were counted a number of schemes, such as the Renewables Obligation, the EU ETS and energy efficiency schemes which could be counted as levies and which acted to increase energy costs even though wholesale prices fell. For industrial users, an increase in network costs of 24.5% was the most significant factor in an electricity price increase of 12.8%. The single largest component of electricity bills remained the wholesale energy price, but  overall increases in bills were driven by rising taxes and network costs. 

Annex 2 Methodology for a bottom up analysis of
industry sectors

The bottom-up case studies presented in the
study compile data from energy intensive industrial sectors and sub-sectors,
where the relative importance of gas and electricity as energy inputs in the overall
energy and total production costs is high. Geographical coverage across the EU
and the presence of big and small players have been factors in selecting the
following sectors:

 Bricks and roof tiles – NACE code 2332
 Wall and floor tiles – NACE code 2331
 Flat glass – NACE code 2311
 Ammonia - refers to several Prodcom codes mainly under NACE
     2015 ‘Manufacture of fertilisers and nitrogen compounds’
 Chlorine - refers to several Prodcom codes under NACE 2013
     ‘Other inorganic basic chemicals’ and also NACE 2014 ‘Other organic basic
     chemicals’
 Aluminium – NACE code 2442
 Steel – NACE code 2410

A standard questionnaire was circulated to
potential respondents in each sector and sub-sector identified with the help of
industry associations. Between August and October 2013, about 110 questionnaires
were filled by respondents. Responses were checked for completeness. For each
sector and subsector, industrial sites that responded to the questionnaires
were sampled according to four main criteria:

 Geographical: include as many Member
     States as possible while accounting for the relative importance of each
     Member State in terms of total EU production capacity in the respective
     sector or sub-sector; 
 Production capacity: ensure that the sample
     reflects the actual distribution of capacities across the EU and its
     regions;
 Production technology: ensure that the sample
     reflects the actual distribution of technologies across the EU and its
     regions;
 Size: ensure that the sample mirrors the
     reality of each sector in terms of proportion of SMEs and larger
     companies.

Based on the number and type of respondents
in each sector as well as their Member State of origin, the criteria above have
had different weight in the definition of samples and implied that, for some
sectors, not all questionnaires received could be fully used.
The need to deal with the confidentiality
of highly sensitive commercial information implied that data was presented
anonymously, aggregated and/or indexed in order to ensure that it could not be
attributed to any specific plant.
A way of dealing with the confidentiality
constraint has been to present sector-specific results by broad regions (e.g.
Central Northern Europe, Southern Europe, etc.). The composition of
geographical regions may vary across sectors analysed due to the location of
respondents, as well as again due to the confidentiality constraint. 
The use of geographical aggregates implied
that no analysis at country level was possible. In order to address this
shortcoming, an assessment has been conducted also for four Member States -
Germany, Italy, Poland and Spain – for which a sufficient number of
questionnaires were collected across all covered sectors so as to allow
country-specific analysis whilst ensuring the anonymity of plants.
The analysis looked first at the level and
components of gas and electricity prices paid by industry operators and at
their evolution over the period 2010-2012 (chapter 1). The collection of data
on electricity and gas consumption and production volumes allowed presenting
the relation between energy intensity and energy prices for anonymous exemplary
plants. An attempt was made in order to assess the impact of energy prices and
their components in terms of unit production costs (chapter 2). For some
subsectors and after ensuring for comparability in terms of consumption range,
it was possible to collect data on the level of electricity and gas prices paid
by plants in some non-EU countries, allowing for comparison with the situation
in the EU (chapter 3 and Annex 4).
The analysis of energy prices composition
distinguishes the following price components: (i) production cost, (ii) network
fees, (iii) non-recoverable taxes and levies (excluding VAT), (iv) RES support
schemes: depending on the Member State where an installation is located, these
are either part of the network fees or levies. Attribution to network fees or
levies is sometimes subject to yearly change.
Energy efficiency and indirect costs (e.g.:
emission costs) and the extent to which these indirect costs were passed on by
utilities onto the final consumers have also been analysed. Changes in costs
and efficiency indicators over a short period of time (between 2010 and 2012)
does not provide a fully-fledged analysis on the observable trends in the
industries. 
A further underlying component of the
electricity price is represented by the CO2 indirect cost, that is,
the CO2 allowance price which is accounted for by electricity
producers either as opportunity or as real cost and is passed over in the
electricity price paid by consumers. However, with only few exceptions, this component
cannot be easily detected as normally it does not appear in the electricity
bill. Therefore, in the case studies presented, an attempt has also been made
to estimate the average CO2 indirect costs by sector and region. The
impact of indirect costs is considered to be already implicitly included in the
other price components reported, in particular in the energy supply component. In
order to estimate CO2 indirect costs, the average electricity
intensity of respondents in each sector and region has been calculated and
associated to regional CO2 emission factors for electricity
production as well as to assumptions in terms of CO2 price
pass-through rate from producers to final consumers. The results are presented
in Error! Reference source not found. in chapter Error! Reference source not
found..
All energy prices collected via the
questionnaire and processed in the analysis exclude exemptions or reduction of taxes,
levies and transmission costs and represent the final unit price paid by
respondents.
The following tables show data on sampling
for each case study:
·        
Bricks and roof tiles
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison 
 23 || 13 || 13 || 13 || 8 || 6 
Northern Europe includes 5 plants: IE, UK,
BE, LU, NL, DK, SE, NO, LT, LV, FI, EE
Central Europe includes 3 plants: DE, PL, CZ, SK, AT,
HU
Southern Europe includes 5 plants: FR, PT,
ES, IT, SI, HR, BG, RO, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
·        
Wall floor tiles
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and margins 
 24 || 12 || 12 || 12 || 6 || 6 || 9 
Central and Northern Europe includes 3
plants: IE, UK, BE, LU, NL, DK, DE, PL CZ, LV, LT, EE, SE, FI
South-Western Europe includes 5 plants: ES,
PT, FR
South-Eastern Europe includes 4 plants: IT,
SI, AT, HU, SK, HR, BU, RO, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculation based on questionnaires
·        
Float glass
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs || Margins 
 10 || 10 || 10 || 7 || 10 || 7 || 4 
All together, the 10 sampled plants represent about 19% of European
production.
Western Europe includes 6 plants: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes 2 plants: BG, RO,
CZ, HU, EE, LT, LV, SK, PL
Southern Europe includes 2 plants: IT, MT,
CY, PT, ES, EL, SI
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculation based on questionnaires.
·        
Ammonia
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs 
 10 || 10 || 10 || 10 || 10 || 7 
All together, the 10 sampled plants represent about 26% of EU27
production
The sample includes 2 small, 4 medium and 4 large-sized plants,
representing all together about 27% of total EU production capacity. The 10
plants are located in 10 different member states.
Western-Northern Europe includes: IE, UK,
FR, BE, LU, NL, DE, AT, DK, SE, FI
Eastern Europe includes: RO, CZ, HU, EE, LT,
LV, SK, PL
Southern Europe includes: IT, MT, CY, PT,
ES, EL, SI, BG
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons. The number of sampled plants per region cannot be
disclosed due to confidentiality.
Source: CEPS, calculation based on questionnaires.
·        
Chlorine
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || Production costs 
 11 || 9 || 9 || 9 || 9 || 5 
All together, the 9 sampled plants represent about 12% of EU27
production
Central-Northern Europe includes 6 plants:
IE, UK, BE, LU, NL, DE, PL, CZ, LV, LT, EE, DK, SE, FI
Southern-Western Europe includes 3 plants:
ES, PT, FR
For remaining MS, no questionnaires were
received and no averages could be calculated.
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons. 
Source: CEPS, calculation based on questionnaires.
·        
Primary aluminium
The evidence presented in the case study
for aluminium is based on data collected via a questionnaire from a sample of
11 out of the 16 primary smelters in the EU, representing more than 60% of EU
primary aluminium production in 2012. These data were also validated and
integrated using the CRU database
No sampling by geographical region is
presented. The averages calculated for the whole sample are compared to averages
obtained for two subsamples: subsample 1 refers to plants which procure
electricity through long-term contracts or self-generation (or long term
contracts) while subsample 2 refers to plants which procure electricity in the
wholesale market.
·        
Steel
Size of the
sample
Number of questionnaires used in the case study
 Received || Selected in the sample || Energy prices trends || Energy bill components || Energy intensity || International comparison || Production costs and Margins 
 17 || 17 || 15 (gas) 17 (electr.) || 14 (gas) 17 (electr.) || 11 (gas) 14 (electr.) || 3 || * 
North-Western Europe includes 9 plants: FR,
BE, LU, NL, IE, UK, DE, AT, DK, FI, SE
Central and Eastern Europe includes 3
plants: PL, SI, HU, RO, BG, CZ, SK, EE, LV, LT
Southern Europe includes 5 plants: IT, ES,
PT, EL, MT, CY
Note that sampled plants do not come from
all the MS in one region. The specific countries cannot be indicated due to
confidentiality reasons.
Source: CEPS, calculation
based on questionnaires.

Annex 3. The merit order effect

Estimates of the surcharge for renewable
energy are estimates of the difference between market prices and revenue of
supported technologies. It is however important to note that these estimates
are not representing the total costs of renewable energy for at least two
reasons: a) they include the decrease in wholesale market prices caused by
renewable energy (the merit-order effect[16]),
but negatively; when renewable energy reduces wholesale electricity
prices, the support level appears larger, as the gap between wholesale prices
and support levels increases, and b) large fractions of the industry in Member
States is partly or wholly exempted[17]
from the surcharge in order to avoid carbon leakage and to ensure that the
industry remain competitive. 
Figure 6: Schematic description of the merit-order
effect (Poyry 2010)
What is the merit-order effect?
The quantity of the merit-order effect
depends on the shape of the merit-order (thereby its name). The figure below
shows how wind electricity injection has different price impacts depending the
time of the day and the marginal supply at that time. An overall estimation of its
overall impact therefore requires an assessment of the impact throughout the
year, hour by hour. 
The merit-order effect is evaluated in
several scientific studies which indicate that the additional supply of
electricity from renewable sources reduces the spot price, and sometime so much
that it outweighs the costs of the subsidies. The table below shows some of the
results of the literature for Member States in Europe; it shows that for wind electricity
in Spain and Ireland the benefits for electricity consumers in terms of
reduction in whole-sale prices outweigh the costs of subsidies. For a range of
renewable technologies that was in the market in 2006 in Germany, the picture
is the same. However, after the significant increase in PV in Germany in the
period 2009 – 2012, the costs of subsidies increased, and the balance got
negative, with costs of subsidies being larger than the benefit of the
reduction in whole-sale prices. 
 Author: || Member State: || Technology: || Merit-order effect: [€/MWh] || Merit-order effects minus support cost [€/MWh] 
 Gil. et al. 2013 || Spain || Wind || 44.9 || 16.7 
 Sensful et al. 2008 || Germany (2006) || RES-E || 95 || 26[18] 
 Saenz de Miera et al. 2007 || Spain || Wind || 51.4 || 12.4 
 O'Mahoney et al. 2011 || Ireland || Wind ||   || 47.7[19] 
 Öko-Institut (2012) || Germany || RES-E ||   || -45[20] 
More information on the merit-order effect
and its magnitude can be found elsewhere[21].
The benefits of reduced whole-sale market price caused by renewable electricity
should however be allocated efficiently to cover the external costs of
increased renewable electricity, like the costs of increased storage and
flexibility in the grid.
 

Annex 4. International comparison of prices of
electricity and gas paid by a sample of EU producers 

ELECTRICITY
Figure 7 Prices of electricity: comparison of
two EU-based brick and roof tile plants and one plant of comparable capacity in
Russia (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 8 Prices of electricity: comparison of
two EU-based brick and roof tile plants and one US-based plant of comparable
capacity (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 9 Prices of electricity: comparison of two EU-based wall and
floor tile plants and one plant of comparable capacity in Russia (€/MWh)
Source: CEPS, calculations based on
questionnaires.
Figure 10 Prices of electricity: comparison of two EU-based wall and
floor tile plants and one US-based plant of comparable capacity (€/MWh)
Source: CEPS, calculations based on
questionnaires.
Figure 11 Electricity price: comparison between three US-based plants and seventeen  steelmakers
in the EU (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 12 Electricity prices for aluminium
smelters in different world countries and regions, 2012 ($/MWh, delivered at
plant)
Source: The EU27 (universe) data comes from
CRU, the data for the 2 subsamples (a total of 11 smelters, including EU27
subsample 1, EU27 subsample 2 and EU27 sample) comes from CEPS, calculations based
on questionnaires. CRU for all international data. 
Figure 13 Electricity prices for aluminium
smelters in different world countries and regions, 2012 ($/MWh, delivered at
plant)
Source: CEPs, calculations based on
questionnaires for the 11 EU-based smelters. CRU for EU27 and international
data
NATURAL GAS
Figure 14 Prices of natural gas: comparison
of two EU-based brick and roof tile plants and one plant of comparable capacity
in Russia (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 15 Prices
of natural gas: comparison of two EU-based brick and roof tile plants and one
plant of comparable capacity in the US (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 16 Prices of natural gas: comparison
of two EU-based wall and floor tile plants and one plant of comparable capacity
in Russia (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 17 Prices of natural gas: comparison
of two EU-based wall and floor tile plants and one plant of comparable capacity
in the US (€/MWh)
Source: CEPS, calculations based on questionnaires.
Figure 18 Natural gas
price: comparison between three US-based plants and fifteen steelmakers in the
EU (€/MWh)
Source: CEPS, calculations based on questionnaires.

Annex 5.
Vulnerable consumers

Defining the concept of vulnerable
customers
Increases in electricity and household gas
prices have given rise to questions on the ability of lower income households to
cope with rising energy bills. The question has been raised as to what kind of
measures should be taken to protect vulnerable customers, though there
is currently no universal definition of this concept.
Some Member States state that the concept
has not been defined as vulnerable customers are covered by national social
policy.  Others use factors such as old age, retirement, unemployment, low
income, disability, poor health, requiring an uninterrupted electricity supply,
large family, being a carer or living in a remote area to define the concept.  
The Third Energy Package requires Member
States to define the concept of vulnerable customers as a first step in
addressing the issue of vulnerability. The table below provides guidance for
defining the concept, setting out the main elements that may drive and/or
exacerbate vulnerability in the energy sector. Although energy vulnerability is
not identical to energy poverty, the latter is implicitly addressed in the
focus on the former.
 
When defining energy vulnerability, one
size may not fit all and a single, EU-wide concept may not be the best approach.
Vulnerability is not a static state and may evolve in parallel to energy sector
developments. Furthermore, consumer status may fluctuate depending on health,
employment and other factors. There is a need for continuous efforts from
Member State authorities to ensure that those who need support receive it at
the appropriate time, whether short- or long-term. Some consumers may be
vulnerable throughout their lifetimes, while others may have a one-off need for
financial or other support or be pushed into temporary vulnerability by events
such as unemployment.
Examples of Member State instruments and
practices
The Commission has worked with
stakeholders, primarily the Citizens' Energy Forum and its Vulnerable Consumers
Working Group (active since March 2012), to provide examples of instruments and
practices in place in Member States, for guidance purposes only. The
instruments it cites are wide-ranging and cover areas from social and housing
policy through to energy. They represent real-life examples rather than best
practice, with the aim of providing ideas of what it is possible to implement
to support vulnerable customers. It is intended that this list will be a
running inventory and be made publicly available so it can be updated as new
practices are introduced at a national level. Its examples are divided under
six main headings: household energy efficiency, financial support,
protection, information and engagement, information sharing between
stakeholders, and physical measures.
Developing the policy mix
Member State authorities can use the table
and the examples of Member State instruments and practices to help define
energy vulnerability and introduce policies to ensure the best possible support
for vulnerable consumers. Finally, it should be noted that social tariffs may
distort the market, do not encourage energy-efficient behaviour, and have a
proportionally higher financial impact on those who fall just outside the
vulnerable classification.

Annex 6. Short description of the GEM-E3 model

The GEM-E3 model is a multi-regional,
multi-sectoral, recursive dynamic computable general equilibrium (CGE) model. The
model allows for a consistent comparative analysis of policy scenarios since it
ensures that in all scenarios, the economic system remains in general
equilibrium. The scope of the GEM-E3 model is general in two terms: it includes
all simultaneously interrelated markets and it represents the system at the
appropriate level with respect to geography, the sub-system (energy,
environment, economy) and the dynamic mechanisms of agent’s behaviour. The
model formulates separately the supply and demand behaviour of the economic
agents which are considered to optimize individually their objective while
market derived prices guarantee global equilibrium. The model considers explicitly
the market clearing mechanism and the related price formation in the energy,
environment and economy markets: prices and quantities are computed
endogenously by the model as a result of supply and demand interactions in the
markets. 
Total demand (final and intermediate) in
each country is optimally allocated between domestic and imported goods, under
the hypothesis that these are considered as imperfect substitutes. Agents’ utility
is derived from consumption by purpose (food, clothing, mobility,
entertainment, etc.) which is further split into consumption by product.
Substitutions are possible depending on relative prices.
The model is dynamic, recursive over time,
driven by accumulation of capital and equipment. Technology progress is
explicitly represented in the production function, either exogenous or
endogenous, depending on R&D expenditure by private and public sector and
taking into account spillovers effects. Moreover it is based on the myopic
expectations of the participant agents.
The model is calibrated to the base year
data set that comprises a full Social Accounting Matrices for each
country/region represented in the model. The SAMs of the of the GEM-E3 model
are based on the GTAP v8 database. Bilateral trade flows are also calibrated for
each sector represented in the model, taking into account trade margins and
transport costs. Consumption and investment is built around transition matrices
linking consumption by purpose to demand for goods and investment by origin to
investment by destination. The initial starting point of the model therefore,
includes a very detailed treatment of taxation and trade. 
Regional model
resolution
 Abbreviation || Country || Abbreviation || Country || Abbreviation || Country || Abbreviation || Country or Region 
 AUT || Austria || GRC || Greece || SVN || Slovenia || ARG || Argentina 
 BEL || Belgium || HUN || Hungary || SWE || Sweden || TUR || Turkey 
 BGR || Bulgaria || IRL || Ireland || ROU || Romania || SAU || Saudi Arabia 
 CYP || Cyprus || ITA || Italy || USA || USA || CRO || Croatia 
 CZE || Czech Republic || LTU || Lithuania || JPN || Japan || AUZ || Oceania 
 DEU || Germany || LUX || Luxembourg || CAN || Canada || FSU || Russian Federation 
 DNK || Denmark || LVA || Latvia || BRA || Brazil || REP || Rest of energy producing countries 
 ESP || Spain || MLT || Malta || CHN || China || SAF || South Africa 
 EST || Estonia || NLD || Netherlands || IND || India || ANI || Rest of Annex I 
 FIN || Finland || POL || Poland || KOR || South Korea || ROW || Rest of the World 
 FRA || France || PRT || Portugal || IDN || Indonesia ||   ||   
 GBR || United Kingdom || SVK || Slovakia || MEX || Mexico ||   ||   
 
Sectoral model
resolution
 Sector || Sector || Power generation technologies 
 Agriculture || Non-metallic minerals || Coal fired 
 Coal || Electric Goods || Oil fired 
 Crude Oil || Transport equipment || Gas fired 
 Oil || Other Equipment Goods || Nuclear 
 Gas Extraction || Consumer Goods Industries || Biomass 
 Gas || Construction || Hydro electric 
 Electricity supply || Transport (Air) || Wind 
 Ferrous metals || Transport (Land) || PV 
 Non-ferrous  metals || Transport (Water) || CCS coal 
 Chemical Products || Market Services || CCS Gas 
 Paper Products || Non Market Services ||   
[1] PRIMES is a European energy system and market model. PROMETHEUS is
a world energy market model. See www.e3mlab.eu
for further details.
[2] The main assumptions of the reference scenario include) GDP
projections based on the report “2012 Ageing report: Economic and budgetary
projections for the 27 EU member states (2010-2060)”, by DG-ECFIN and GHG emissions,
RES deployment and energy efficiency consistent with the EU Roadmap for moving
to a low carbon economy in 2050.
[3] Labour productivity follows DG-ECFIN (2012) and autonomous energy
efficiency improvements follows PRIMES 2013 Reference scenario.
[4] Energy price increases are projected by a number of studies
including the WEO (2013) and EIA (2013). The main drivers of energy prices can
be classified in the following categories: i) Activity level/Demand, ii)
Reserves, iii) Production costs and iv) market power. Depending on the
assumptions on the reserves and GDP growth made by each study the price
increases differ. Here all variants that include energy prices higher than the
reference are conceived only as stylized cases aiming at exploring the level of
resilience of EU economy towards energy price changes and at studying the
consequences depending on the cause of energy price rise.
[5] 2015 is the first projection year; the year 2010 is a projection in
modelling terms because the database uses 2007 as base statistical year but the
2010 projection does not vary by scenario. The resolution of the model in terms
of different sectors and countries is the largest ever produced with GEM-E3.
[6] Depending on the choice of the driver the impact on the economy of
the same price increase is different. Here a variety of drivers is selected in
order to get a comprehensive picture of the different possible outcomes.
[7] This could be due to the discovery of new reserves.
[8] The regional and
sectoral aggregations of the model are summarized in the Appendix.
[9] The Global Trade Analysis Project (GTAP) is a global network of
researchers and policy makers conducting quantitative analysis of international
policy issues. GTAP is coordinated by the Centre for Global Trade Analysis in Purdue
University's Department of Agricultural Economics.
[10] Available at: http://globalchange.mit.edu/Outlook2012 
[11] (Exports + Imports) / GDP. In this calculation exports and imports
do not include intra-EU trade.
[12] These two countries represent nearly 30% of total EU exports
[13] These countries represent 33% of total EU imports
[14] Austria, Belgium, Denmark, Germany, Spain, Finland, France, Greece,
Ireland, Italy, Luxembourg, Netherlands, Portugal, Sweden, UK.
[15] See  http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/NATIONAL_REPORTS/National%20Reporting%202010/NR_En/E10_NR_Denmark-EN_v2.pdf 

[16] Renewable electricity typically has insignificant operational
costs, and thus shifts the merit-order to the right, thus decreasing the
whole-sale market price for electricity. The merit-order effect is essentially
a shift of wealth from incumbent producer's surpluses to consumers.
[17] 47% of German industry's electricity consumption is fully part of
the EEG system (financing of RES in Germany)
[18] Assuming an average value of renewable energy at spot market of 40
€/MWh. 
[19] The benefit is calculated at 141 € Million for 2009. 47.7 €/MWh is
calculated by dividing by the amount of wind power in 2009: 2955 GWh.
[20] Figure 13 in Öko-Institut (2012) Strompreisentwicklungen im
Spannungsfeld von Energiewende, Energiemärkten und Industriepolitik. Der
Energiewende-Kosten-Index (EKX)
[21] More literature is listed below:
 1.Delarue, Erik D., Luickx, Patrick J., D’haeseleer, William D.
2009. The Actual Effect of Wind Power on Overall Electricity Generation Costs
and CO2 Emissions. Energy Conversion and Management 50 (2009) 1450–1456.
2.Gil, Hugo A., Gomez-Quiles, Catalina, Riquelme, Jesus,2012.
Large-scale wind power integration and wholesale electricity trading benefits:
estimation via an ex post approach. Energy Policy 41(February), 849–859.
3.Jonsson, Tryggvi, Pinson, Pierre and Madsen, Henrik. 2009. On the
Market Impact of Wind Energy Forecasts. Energy Economics (2009).
4.Munksgaard, J. and Morthorst, Poul Erik. 2008. Wind Power in the
Danish Liberalised Power Market – Policy Measures, Price Impact and Investor
Incentives. Energy Policy 2008.
5.O′Mahoney, Amy, Denny,E leanor, 2011.The merit order effect of
wind generation in the Irish electricity market ,Washington,DC.
6.Saenz Miera, Gonzalo, Del Rio Gonzales, Pablo and Vizciano,
Ignacio. 2008. Analysing the Impact of Renewable Energy Support Schemes on
Power Prices: The Case of Wind Energy in Spain. Energy Policy 36 (2008)
3345–3359.
7.Sensfuss, Frank. Ragwitz, Mario and Genoese, Massimo. 2007. Merit
Order Effect: A Detailed Analysis of the Price Effect of Renewable Electricity
Generation on Spot Prices in Germany. Fraunhofer Institute Systems and
Innovation Research. Energy Policy 36 (2008) 3086– 3094.
8.Unger, Thomas, Erik Ahlgren, 2005. Impacts of a common green
certificate market on electricity and CO2-emission markets in the Nordic
countries. Energy Policy 33(16),2152–2163.
9.Weigt, Hannes. 2008. Germany’s Wind Energy: The Potential for
Fossil Capacity Replacement and Cost Saving. Applied Energy 86 (2009)
1857–1863.