Annual Electricity Report

Transcription

2014 Annual
Electricity Report
Published on 29/01/2015
© 2015 RTE Réseau de transport d’électricité
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2014 Annual Electricity Report, particularly:
> If the documents, data or information are used, exploited or distributed without citing RTE as the author or owner;
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of the documents, data or information in the 2014 Annual Electricity Report, particularly any loss of profit or financial or commercial losses.
summary
Part 1
Part 3
Warmer temperatures
resulting in lower demand 6
Consumption declining 25
Gross consumption lower in most countries
26
Gross consumption contracted sharply in 2014 due
to mild weather
7
France, Germany, Spain, Italy and Great Britain
together home to 60% of European power
generation 26
Weather-adjusted consumption was unchanged 8
9
Consumption by SMI/SMEs, residential and
professional users down slightly
France still exports more than any other European
country 28
10
Peak demand the lowest on record since 2004
11
France has the highest temperature sensitivity in
Europe29
Industrial demand stabilising Power demand still greatly impacted by temperature
sensitivity 12
Load shedding and load curtailment schemes
gaining ground 13
Market prices trending
lower across all europe 31
Part 2
Wind and photovoltaic
power development
trending higher again Part 4
Exports up sharply
33
New load shedding capacity being developed 41
RTE creating new market mechanisms
43
14
Renewable energies accounting for larger
share of consumption
15
Nuclear share of generation stable,
conventional thermal power down sharply 21
The transmission grid corrects imbalances
between generation and consumption
24
Part 5
RTE is investing today in the
grid of the future 44
RTE improving the quality of electricity 45
RTE standing up for the environment and
biodiversity 46
Loss rate stable in 2014 46
RTE invested close to €1.4 billion in 2014
46
Underground network expanded in 2014
47
RTE already working on the grid of the future 49
Glossary53
1
Executive Summary
CARBON EMISSIONS DECREASING
DUE TO LOWER DEMAND
AND RENEWABLE ENERGY
DEVELOPMENT
As France prepares to host the 21st international
climate conference, the 2014 edition of RTE’s Annual
Electricity Report illustrates, once again, how sensitive
power consumption is to climate conditions. In 2014,
the hottest year on record since the beginning of
the 20th century according to Météo France, gross
power consumption contracted by 6% versus 2013
and ended the year at 465.3 TWh, the lowest level
since 2002.
This decline was attributable in large part to weather
conditions. With temperatures 0.5°C above reference
temperatures and only dipping below 5°C very rarely
in the winter, electric heating was used less during
the year.
In the absence of any truly cold spells, power demand
peaked at 82.5 GW on 9 December 2014. Peak
demand had not been this low since 2004. That being
said, the temperature sensitivity of demand in winter
is still close to 2,400 MW/°C.
Such large swings in electricity consumption from
one year to the next, both in annual energy and peak
demand terms, underscore the need to make the
power system adaptable to increasingly unpredictable
weather patterns. Though underlying trends
probably point to warmer average temperatures, it is
impossible to predict the frequency and intensity of
cold spells going forward, or the regional variability
of these patterns. These elements of uncertainty are
such that supply must be very flexible to keep up with
swings in demand.
2
2014 Annual Electricity Report
Along these lines, to assure continued coverage of
the peaks in demand to which the power system is
still exposed, RTE is introducing market mechanisms
designed to consistently secure supply, such as
demand response schemes and the capacity
mechanism.
Electricity consumption was moderate in 2014, and
CO2 emissions in the power sector contracted by
40% from the year-earlier level. Emissions ended the
year at 19 MtCO2e.
One reason for this decline is that less use was made
of fossil fuel thermal power plants (coal, gas and oil),
which are used for backup generation. Their output
was down 40% from 2013. Lower consumption
has been impacting CO2 emissions reductions in
recent years as well. For instance, a 6% contraction
in demand between 2010 and 2011, though offset
in part by rising exports, went hand in hand with a
20% decrease in CO2 emissions. This phenomenon
confirms that demand-side management measures
undertaken in France have positive effects on the
environment.
At a more structural level, CO2 emissions are
decreasing due to changes in the energy mix and the
fact that renewable sources are accounting for an ever
larger share of generation. Wind and photovoltaic
power development had slowed in recent years but
began trending higher again in 2014, with close to
1,900 MW of new capacity installed. France is now
home to more than 9,100 MW of wind power and
almost 5,300 MW of photovoltaic capacity. With
this growth, and the decommissioning of 1,300 MW
of fossil fuel thermal capacity, the French energy
mix continues to evolve in such a way as to support
an energy transition designed to reduce carbon
emissions.
Executive Summary
As such, for the first time in 2014, more electrical
energy was produced from renewable sources
excluding hydropower (27.9 TWh) than from fossilfired thermal plants. More than half of this total
was wind power and the balance was split between
photovoltaic, wood-energy and other solid biofuels.
Wind production peaked on 27 December 2014 at
just over 7,000 MW with a capacity factor of 80%.
Photovoltaic generation peaked on 17 May 2014 at
3,700 MW with a capacity factor of 80%. New records
were set in both cases.
This same phenomenon can be seen across Europe as
a whole, where power demand is stagnating or even
falling. Between mid-2013 and mid-2014, European
electricity consumption fell 1.5% compared with the
year-earlier period. Demand contracted by more
than 4% in Germany and more than 2% in Italy and
Switzerland, and by about 0.7% in Spain. Though
these results have not been adjusted for weather
effects, which are much less pronounced elsewhere
in Europe than in France, they most likely reflect a
structural trend.
In addition, runoff was fairly high during the year:
hydropower generation reached 68.2 TWh, the
second highest level in the past decade after 2013,
which had been a truly exceptional year.
In France, power consumption in heavy industry had
contracted for three years but stabilised in 2014 at
67.4 TWh. Trends were nonetheless mixed in the
different sectors of economic activity. For instance,
demand declined in the paperboard sector (-7.1%),
car manufacturing (-4%) and rail transport (-2.6%), but
increased in the chemicals (+2.1%) and steel industries
(+2.2%), as well as in metallurgy (+6.2%).
All of these favourable conditions combined to allow
renewable energy sources to cover almost 20% of
power demand in France. This in turn helped reduce
carbon emissions.
POWER DEMAND EXCLUDING
WEATHER IMPACTS STABILISED
AGAIN AS A RESULT OF THE
ECONOMIC CRISIS AS WELL AS
ENERGY EFFICIENCY MEASURES
A weak economy and energy efficiency measures also
combined to help keep demand in check. Adjusting
2014 figures for climate impacts to show results at
so-called normal weather conditions, power demand
in France contracted by 0.4% during the year. The
slump in growth observed over the past four years
now thus continued, confirming that electricity
consumption in France is no longer trending higher.
In reality, the drop in overall power demand in France
was driven by declining electricity consumption
(including own consumption) amongst users
connected to the distribution grids – SMI/SMEs,
professionals and residential consumers – which
account for a much larger share of demand than heavy
industry. Demand had risen steadily for years and then
showed signs of stabilising last year, but 2014 saw the
first decline on record, with consumption falling by
about 0.5% versus 2013. This decline reflects a general
slowing of economic activity, which tends to cause
consumption by SMI/SMEs and professional users to
decrease, and could put some downward pressure
on household demand as well. Energy efficiency
measures put into place for equipment and buildings,
together with the decreasing share of electric heating
in new construction following the implementation of
the 2012 Building Energy Regulation, undoubtedly
played a role as well.
3
Synthèse Summary
Executive
It was also a challenging year for fossil fuel thermal
generation, which contracted on the whole. The coal
segment was the most impacted, with output falling
58% compared with 28% for gas. Coal-fired plants,
several of which were shut down, produced 6 TWh
less than gas-fired facilities.
This shift from coal to gas, which emits less CO2, also
contributed to the sharp decline in carbon emissions.
However, economic conditions remain worrisome for
combined-cycle gas plants in France. Like last year,
some facilities were taken offline during the summer
months.
Due to a combination of declining demand and
plummeting fossil fuel prices, average spot prices
declined over the year in Europe and dropped to
€34.6/MWh in France. Compared with neighbouring
countries, French spot prices were among the
lowest, with Germany alone posting lower prices on
wholesale markets. Average annual spot prices in
the Central West Europe zone, comprising Germany,
France and Benelux, have remained within the €32.4
to €41.2/MWh range over five years.
AS THE ENERGY TRANSITION
CONTINUES, GROWING USE OF
INTERCONNECTIONS CONFIRMS
THE NEED TO START WORKING
NOW TO ADAPT THE POWER GRID
TO THE CHALLENGES THAT LIE
AHEAD
Because domestic consumption was weak and prices
were relatively low in the French market, France was
able to help cover needs in neighbouring countries
by exporting more electricity. The export balance
4
ended 2014 at 65.1 TWh, the highest level since 2002.
Total imports and exports reached 119.8 TWh, which
was 7.4% more than in 2013.
In terms of hourly power demand averaged over each
month, export balances exceeded 5 GW throughout
the year, including in winter. France was in an import
situation during some 30 hours over the year and was
not a net energy importer on any given day.
Analysis of exchanges at each border underscores the
increasing impact of an evolving European energy mix
and the growing share of renewable energy sources.
Because wind power output varies between seasons
and week to week and photovoltaic generation moves
according to daily cycles, electricity flows between
European countries are fluctuating more and more.
France imported more from Germany than it exported
during the year, but exchanges were more balanced
than in the past with the import balance ending the
year at 5.9 TWh, down from almost 10 TWh in 2013,
reflecting the relative weakness of French prices. This
lower balance does not mean that exchange volumes
contracted, but rather that periods of imports and
exports were more balanced, though fluctuations
continued to increase in magnitude. Interconnections
between France and Germany were saturated in one
direction or the other about half the time.
Exchanges with Belgium were significantly impacted
by the unavailability of nearly half of Belgian nuclear
capacity. France’s export balance with Belgium
increased (16.5 TWh). Capacity for exports from
France to Belgium was saturated most of the time.
Export balances with all other countries with which
France shares a border increased. France exported
to Spain two thirds of the time, importing only when
renewable generation in Spain surged, causing prices
to fall below French prices. Interconnections between
Executive Summary
Synthèse
France and England showed high availability rates
in 2014. This capacity was used for exports during
more than 99% of total hours during the year, and
was saturated 90% of the time. France once again
exported much more to Italy than it imported, and
export capacity to that country increased by 400
MW in October 2014 after the transalpine grids were
reinforced.
This growing reliance on interconnector capacity
to pool and optimise the use of different energy
sources, based on where and when they are available
and economically competitive in Europe, only
strengthens RTE’s commitment to adapt the grid to
meet the challenges of the future.
RTE’S INVESTMENT PROGRAMME
IS DESIGNED TO ASSURE QUALITY
SERVICE FOR CUSTOMERS OVER
THE LONG TERM AND TO PROMOTE
NETWORK INTEGRATION
In 2014, RTE invested a total of €1,374m within the
perimeter regulated by the CRE, including €1,243m
for grid infrastructure. These investments chiefly
targeted the accommodation of renewable energies,
ongoing construction of the direct current line to
strengthen interconnection capacity between France
and Spain via the Eastern Pyrenees, the replacement
of conductors to make flows more secure on the
400 kV line between Montélimar and Lyon, and the
enhancement of security of supply to the regions
(PACA and Vendée). One highlight of the last quarter
of 2014 was the final test phase of the “PACA safety
net”, which is scheduled to be deployed early in 2015.
These developments are also intended to assure
that electricity quality will meet high standards over
the long term. In 2014, equivalent outage time for
consumers connected to the transmission grid was 2
min 46 sec, which was below the average for the past
ten years.
Outage frequency has also been factored into the
incentive regulation since August of 2013. The average
number of short or long outages experienced during
the year by RTE’s distributor and industrial customers
(excluding the energy and rail sectors) was 0.46 in
2014, below the average for the past ten years and
within the 0.6 limit set out in incentive regulation.
Lastly, integrating infrastructure into landscapes
remained a top priority for RTE, as was notably
evidenced by the greater use of undergrounding
technologies. At the end of 2014, the public
transmission system had 105,331 km of circuits in
operation. The length of underground circuits is
steadily increasing, while the length of overhead
circuits was stable over the year, after 2013 saw
the VHV Cotentin-Maine line go into service. The
undergrounding rate for new 63 kV and 90 kV
infrastructure has averaged close to 92% over the
past three years.
5
Part 1
Warmer
temperatures
resulting in lower
demand
6
Warmer temperatures resulting in lower demand
Gross consumption contracted sharply in 2014 due to mild
weather
Gross consumption in mainland France contracted by
6%, or 29.8 TWh, between 2013 and 2014, ending the
year at 465.3 TWh. This was the lowest level on record
since 2002.
Gross consumption
The decrease was attributable to particularly warm
temperatures throughout the year.
Though actual temperatures were on average 0.5°C
above reference temperatures, they held at above
5°C nearly all winter, which depressed demand during
the winter months because heating was not used
as much. Conversely, relatively low temperatures in
summer limited the use of cooling systems, and thus
drove national demand down. Temperature differences
between 2013, which was a cold year, and 2014,
characterised by very mild weather, shaved 27.6 TWh
from electricity consumption.
465.3
495.1
513.1
478.8
486.7
494.5
480.4
478.4
483.2
479.6
451.1
500
468.4
550
489.5
TWh
450
400
350
300
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Temperature trends in France* compared with reference temperatures
°C
30
25
20
15
10
5
0
-5
jan
feb
mar
apr
may
jun
jul
aug
sep
oct
nov
dec
Reference temperature
* Calculated based on data from 32 weather stations located across France
7
Average temperatures in 2014
Weather-adjusted
consumption was unchanged
January to March
Adjusted for weather, consumption contracted by 0.4%
to 478.4 TWh.
Analysing weather-adjusted consumption trends
requires excluding the energy sector from the calculation.
Indeed, the adoption of a new uranium enrichment
process at Eurodif severely impacted that sector in 2012
by, leading to a steep decline in consumption.
Consumption adjusted for weather and the
29th day in February, excluding energy
withdrawn by the energy sector
440
474.1
476.7
476.3
471.4
461.5
468.9
462.6
448.1
444.9
432.1
460
437.1
480
455.5
500
April to September
476.4
TWh
420
400
380
360
340
October to December
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Stripping out the impact of weather and the energy
sector, consumption contracted by 0.5%. This was the
fourth year in a row that annual electricity consumption
in France has shown signs of stabilising.
The monthly breakdown of consumption, excluding the
energy sector, is similar to that observed over the past
five years.
Source: Météo France
8
Consumption adjusted for weather effects and the 29th day in February excluding energy withdrawn
by the energy sector
TWh
60
Monthly trends
52.9
55
50.7
50
45.7
45
44.5
40
43.1
37.2
37.1
33.5
35
33.6
32.2
32.8
30.8
30
25
20
jan
feb
mar
apr
may
jun
2008
2009
2010
2011
2012
2013
Industrial demand stabilising
jul
aug
sep
oct
nov
dec
2014
Consumption in car manufacturing industry
(seasonally adjusted)
Consumption in heavy industry excluding
energy sector (seasonally adjusted)
TWh
400
350
300
250
200
150
Conversely, consumption increased in other sectors,
including chemicals (+2.1%), which is still benefiting
from buoyant exports, steelmaking (+2.2%), which
is recovering after several years of declines, and
metallurgy (+6.2%), which is notably benefiting from a
vibrant aerospace market.
Consumption in metallurgy industry
GWh
5.0
750
jan
au -05
gjan 05
au -06
gjan 06
au -07
gjan 07
au -08
gjan 08
au -09
gjan 09
au -10
gjan 10
au -11
gjan 11
au -12
gjan 12
au -13
gjan 13
au -14
g
de -14
c-1
4
6.8
6.6
6.4
6.2
6.0
5.8
5.6
5.4
5.2
GWh
jan
au -05
gjan 05
au -06
gjan 06
au -07
gjan 07
au -08
gjan 08
au -09
gjan 09
au -10
gjan 10
au -11
gjan 11
au -12
gjan 12
au -13
gjan 13
au -14
g
de -14
c-1
4
Power consumption by industrial customers directly
connected to the public transmission system, including
own consumption but excluding losses and the energy
sector, reached 67.4 TWh. The figure was broadly
unchanged from 2013, after three consecutive years of
declines. This trend is visible below in the seasonallyadjusted monthly consumption figures for heavy
industry excluding the energy sector.
700
650
600
550
500
jan
au -05
gjan 05
au -06
gjan 06
au -07
gjan 07
au -08
gjan 08
au -09
gjan 09
au -10
gjan 10
au -11
gjan 11
au -12
gjan 12
au -13
gjan 13
au -14
g
de -14
c-1
4
This stability is a reflection of mixed trends in different
parts of industry. Consumption fell in some sectors.
Examples include paper/paperboard (-7.1%) and car
manufacturing (-4%), which were hurt by the economic
crisis, as well as rail transport (-2.6%), which was impacted
by social movements in June.
A more detailed analysis of sector trends can be found
in the 2014 Generation Adequacy Report.
9
Consumption by SMI/SMEs,
residential and professional
users down slightly
Customers connected to distribution grids, which
include SMI/SMEs and residential and professional users,
along with any losses associated with energy withdrawn,
edged down by 0.5% between 2013 and 2014.
Growth had already begun to slow in 2013, after four
years of annual average increases of 1%, as illustrated
by the series below showing seasonally adjusted
consumption on distribution networks.
Trends in adjusted regional
consumption
Weather-adjusted electricity demand increased by an
average 3% a year between 2006 and 2013 in France as
a whole. Analysis of regional consumption patterns over
that period reveals mixed underlying trends.
Trends in adjusted consumption
between 2006 and 2013
Consumption by SMI/SMEs and residential
and professional users
TWh
34
33
32
31
30
29
28
27
jan
au -05
gjan 05
au -06
gjan 06
au -07
gjan 07
au -08
gjan 08
au -09
gjan 09
au -10
gjan 10
au -11
gjan 11
au -12
gjan 12
au -13
gjan 13
au -14
g
de -14
c-1
4
26
This trend is a consequence of the downward pressure
the economy has put on business levels for SMI/SMEs
and professionals and, to a lesser degree, household
spending. New energy efficiency directives and
regulations governing equipment and buildings are
beginning to bear fruit. At the same time, the share of
electric heating in new buildings decreased after the
2012 Building Energy Regulation went into effect, and
the decline was amplified by a drop in new construction
(for more information, please see the 2014 Generation
Adequacy Report).
10
Increase of more than 5%
Increase of less than 5%
Stable
Decrease of less than 5%
Decrease of more than 5%
Adjusted consumption in Brittany, Lower Normandy,
Poitou-Charentes, Pays de la Loire and LanguedocRoussillon rose by almost 10% between 2006 and 2013,
which was three times faster than the national average.
The difference between consumption patterns in these
regions and the country as a whole is explained primarily
by demographic growth trends in these regions and the
proportion of residential/professional users there.
Conversely, adjusted consumption in Alsace and Lorraine
contracted sharply (by 6% and 11%, respectively), the
economic crisis having taken a significant toll on heavy
industry in both regions. Electricity demand for heavy
industry has declined by 36% in Alsace and by 28% in
Lorraine since 2006, compared with a national average
of -14%. More details about these developments can
be found in the Regional Electricity Reports and their
executive summaries.
Peak demand the lowest on
record since 2004
92,600
82,540
91,820
92,400
84,420
88,960
86,280
86,020
83,540
81,400
79,730
100,000
79,590
The highest level of demand recorded in 2014 was on 9
December, at 7pm, with 82,540 MW at a temperature of
4.3°C, which was 1.4°C below the reference temperature.
This demand peak, the lowest on record since 2004,
reflected the mild temperatures observed throughout
the year.
96,710
MW
120,000
102,100
Peak demand levels since 2001
80,000
60,000
40,000
20,000
01
-1
2
02 -17
-1
2
03 -10
-0
1
04 -19
-1
2
05 -22
-0
2
06 -28
-0
1
07 -27
-1
2
08 -17
-1
2
09 -15
-0
1
10 -07
-1
2
11 -15
-0
1
12 -04
-0
2
13 -08
-0
1
14 -17
-1
209
0
Estimated adjusted power demand during evening peak (7pm) in winter months
MW
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
October
2008
2009
November
2010
2011
December
2012
January
2013
February
March
2014
These estimates are based on reference temperatures.
They show that, under reference conditions, demand at the evening peak time has been flat since 2008.
Demand peaks at about 7pm because tertiary sector activities are still continuing at that time, while rail
transport is spiking and evening domestic activities are getting under way. Every year, winter temperatures
drive consumption higher as heating is switched on. However, the additional electricity consumed depends on
whether winter temperatures are mild or cold. 11
Demand was at its lowest on 17 August, at 29,500 MW,
a level that has been stable for ten years.
Trends in maximum and minimum demand
The temperature sensitivity of power demand varies
over the course of a given day. It is estimated at about
2,400 MW per degree Celsius in winter on average.
MW
120,000
53,070 MW
62,970 MW
71,510 MW
64,800 MW
40,000
56,620 MW
60,000
52,530 MW
100,000
80,000
RTE uses a model that distinguishes between
temperature-sensitive and non-temperature-sensitive
demand to calculate weather-adjusted consumption.
This model illustrates that it is the temperature-sensitive
share that determines the overall demand trend.
20,000
0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Max demand
Min demand
Power demand still greatly
impacted by temperature
sensitivity
Power demand in France is highly sensitive to
temperatures, notably during the winter months, given
the large installed base of electric convection heaters.
This is why the warm temperatures of 2014 brought
demand to such low levels.
Insofar as this temperature sensitivity is primarily the
result of electric heating, the types of heating systems
installed in new homes can impact it. Indeed, since the
2012 Building Energy Regulation took effect, the share
of electric heating in new build has plummeted. This shift
is liable to keep the increase in temperature sensitivity
in check going forward. However, new homes only make
up a very small portion of existing housing stock, so this
impact will only be visible over the long term.
Other end-uses besides heating can also contribute, to a
lesser degree, to increasing the share of power demand
that is sensitive to temperatures, including sanitary hot
water production, cooking and cold production.
The opposite trend is visible in the summer months,
when warmer temperatures tend to drive power demand
up due notably to the use of air conditioning. In France,
however, demand is much less sensitive to temperatures
in summer than in the winter months.
Share of electric heating in new homes
Gross power demand and temperature-sensitive
share in the winter of 2013-2014 (Nov.-March)
MW
%
80
70
100,000
60
90,000
80,000
50
70,000
40
60,000
30
50,000
20
40,000
10
30,000
0
20,000
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
10,000
Source: BatiEtude
0
Gross demand
12
Temperature-sensitive share
Load shedding and load
curtailment schemes gaining
ground
Trends in power demand and generation
in PACA in 2014
TWh
5
During the 2013-2014 season, there were no EcoWatt
alerts, thanks to exceptionally warm weather and high
availability rates for generation resources and the grid.
The scheme is continuing to attract more supporters
with membership bases of 52,400 in Brittany and 26,000
in the PACA region.
Trends in power demand and generation
in Brittany in 2014
3
2
1
Generation
Ju
ly
Au
g
u
Se
pt st
em
be
r
O
cto
No ber
ve
m
De ber
ce
m
be
r
nu
ar
y
br
ua
ry
M
ar
ch
Ap
ril
M
ay
Ju
ne
0
Ja
RTE is continuing to promote the EcoWatt Brittany
and EcoWatt Provence Azur schemes in partnership
with local authorities. These schemes give residential
consumers, local authorities and companies in Brittany
and the PACA region an opportunity to proactively
reduce their electricity consumption in winter, during
hours when demand is peaking. The schemes proved
efficient during colder winters by shaving some 3% from
demand during peak hours.
4
Fe
EcoWatt in Brittany and Provence-Côte
d’Azur
Consumption
Electricity produced in the PACA region fell
16% in 2014 due to declines in hydropower and
thermal generation. The region imported more
than half of the electricity required to meet
demand in 2014. An insufficient local high-voltage
grid, together with fast-rising demand peaks over
the past ten years, have left the PACA region
vulnerable. The PACA safety net to be deployed
in 2015, as discussed in part 5, will help strengthen
the transmission grid.
TWh
3.0
2.5
2.0
1.5
1.0
0.5
Generation
Ju
ly
Au
Se gus
t
pt
em
be
r
O
cto
No ber
ve
m
De ber
ce
m
be
r
Ja
nu
a
Fe ry
br
ua
ry
M
ar
ch
Ap
ril
M
ay
Ju
ne
0
Consumption
Brittany generated enough electricity in 2014
to cover 13% of its demand. The balance was
generated elsewhere and brought in over the
grid. During peak hours in winter, the grid can
reach its maximum transmission capacity. In this
case the risk of power outages in Brittany is high,
particularly if there is an incident on the network
or at a generation facility.
Lastly, RTE has been managing the Tempo signal since 1
November 2014 along with its transposition to éCO2mix.
Power supply offers like Tempo include different pricing
levels that vary depending on the time and colour
coding of the day. “Red days” correspond to the times
of year when demand is very high, “white days” to times
of moderate demand, and “blue days” to periods when
demand is at its lowest. Prices corresponding to each
type of day are set by the individual suppliers offering
such plans. It will now be possible to receive messages
about whether days are red or white on mobile devices.
A special page devoted to these tariff signals has also
been created on the Web.
13
Part 2
Wind and
photovoltaic power
development
trending higher
again
14
Wind and photovoltaic power development trending higher again
Renewable energies
accounting for larger share
of consumption
Installed power generation capacity in France increased
by 0.5%, or 662 MW, in 2014.
Renewable energies continued to account for a larger
share of that capacity, with 1,889 MW of wind and
photovoltaic power added and 1,296 MW of fossil-fired
thermal capacity withdrawn.
Installed
capacity as of
2014-12-31
(MW)
Nuclear
Fossil-fired
thermal
Of which Coal
Oil
Gas
Hydropower
Wind power
Photovoltaic
Other energy
sources
Total
Total France
Share of
Capacity Change vs. Change
installed
(MW) 2013-12-31 (MW)
capacity
63,130
+0.0%
+0
48.9%
24,411
-5.0%
-1 296
18.9%
5,119
8,883
10,409
25,411
9,120
5,292
-19.5%
-0.7%
+0.1%
-0.1%
+11.8%
+21.2%
-1 240
-65
+9
-23
+963
+926
4.0%
6.9%
8.0%
19.7%
7.2%
4.1%
1,579
+6.2%
+92
1.2%
128,943
+0.5%
+662
100%
Energy produced
Net generation
Nuclear
Fossil-fired
thermal
Of which Coal
Oil
Gas
Hydropower
Wind power
Photovoltaic
Other energy
sources
Of which
renewable
TWh
540.6
415.9
Change
Share of
2014/2013 generation
-1.8%
100%
3.0%
77.0%
27.0
-39.6%
5.0%
8.3
4.4
14.3
68.2
17.0
5.9
-58.2%
-10.5%
-28.2%
-9.7%
+6.7%
+27.2%
1.5%
0.8%
2.7%
12.6%
3.1%
1.1%
6.6
+6.7%
1.2%
5.1
+8.4%
0.9%
Energy produced
TWh
PHOTOVOLTAIC
5.9
WIND
OTHER ENERGY
SOURCES
6.6
17.0
HYDRO
68.2
FOSSIL-FIRED
THERMAL
27.0
Total generation in France reached 540.6 TWh in 2014,
or 1.8% less than in 2013. This decline in generation,
triggered by a decrease in power demand, drove the
export balance up sharply for the year.
NUCLEAR
415.9
Share of renewable energy
sources
In 2014, 19.5% of the power consumed in France came
from renewable sources1. This percentage was slightly
higher than in 2013.
1 Calculation method drawn from EU directive 2009/28/EC: Production from pumped storage units less 70% of consumption for pumping, municipal waste
incineration plants counted at 50%, in relation to gross consumption. This does not correspond to the calculation under the official methodology, which
assumes that results are adjusted for weather.
15
Share of renewable generation in total annual
electricity consumption
Wind power
Installed capacity
%
25
19.3 19.5
20
13.4
16.8
13.3
10
Installed wind capacity
MW
9,000
9,120
8,000
2010
2011
2012
2013
2014
6,000
5,764
5,000
Like in 2013, more than half of renewable energy
generation excluding hydropower corresponded to wind
power. Wind conditions were particularly favourable for
that industry early in the year and during the summer.
Photovoltaic generation increased by more than 27%
from the 2013 level, rising to 5.9 TWh. Power generated
by combustible renewables (municipal waste, paper
waste, biogas, wood energy and other solid biofuels)
rose 8.4% to 5.0 TWh.
All in all, renewable generation excluding hydropower
increased in 2014 and accounted for 5.2% of total
generation, or 28.0 TWh, which was higher than the
percentage of fossil fuel generation. Adding in all
hydropower generation, production from renewable
sources reached 96.1 TWh.
4,574
4,000
3,327
2,250
2,000
1,502
752
1,000
393
219
0
3,000
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year-on-year change
Installed capacity at 31 December
Installed capacity exceeded 700 MW in five regions:
Champagne-Ardenne, Picardy, Brittany, Centre and
Lorraine. It actually climbed above 1,300 MW in Picardy
and 1,500 MW in Champagne-Ardenne.
Map of installed wind capacity
Breakdown of renewable generation
HYDROPOWER
WIND POWER
71%
18%
PHOTOVOLTAIC
6%
OTHER RENEWABLE
SOURCES
5%
More than 1,000 MW
700 to 1,000 MW
300 to 700 MW
16
963
2009
621
2008
8,157
822
2007
7,536
6,714
7,000
1,247
0
1,190
5
950
15
14.5 14.0 14.9
Onshore wind capacity expanded in 2014, with
an additional 963 MW connected to the grid. This
represents an 11.8% increase from 2013. Total installed
wind power capacity rose to 9,120 MW of which 414
MW is connected to the RTE grid and 8,706 MW to the
networks of ERDF and local distribution companies.
100 to 300 MW
0 to 100 MW
Wind power generation
Wind power generation rose by 6.7% from the
end-December 2013 level, to 17.0 TWh.
On average, wind power covered 3.6% of total demand
as at end-December 2014, compared with 3.3% a year
earlier. Coverage peaked at 16.0% on Sunday, 11 May at
4:00 pm, which was nonetheless below the record high
of 16.2% observed on 27 October 2013.
TWh
17.0
15.9
14.9
18
16
Power consumption covered with wind power
500
14
12.1
12
7.9
8
5.6
6
4.0
4
2
0
Number of half-hour intervals
9.7
10
0.4 0.6 1.0
2.3
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Output peaked on Saturday 27 December, at 4:00
am, with 7,238 MW produced, the highest level ever
recorded. During this peak, the capacity factor of
79.8% was close to the level seen on 23 December 2013
(6,529 MW, capacity factor of 80.2%).
400
300
200
100
0
0%
2%
4%
6%
8%
10%
12%
14%
16%
Coverage rate
2013
2014
MW
6,994
7,000
6,439 6,510
7,238
6,312
2,801
2,059
1,687
1,292
1,276
995
1,000
2 790
1,327
2,000
4,406
4,368
1,736
3,000
4,916
2,053
4,000
5,982
5,091
1,456
4,915
2,933
5,000
3,681
6,000
0
jan feb mar apr may jun jul aug sep oct nov dec
Average output
Maximum output
17
Breakdown of wind power generation
over a year
Monthly wind capacity factor
78.6 79.0
78.5
58.8
10
23.0
31.7
18.9
51.2
30.9
66.8
11.3
20
52.2
15.5
30
44.7
50
57.6
14.9
59.5
60
14.8
70
40
79.8
74.5
24.3
80
17.4
90
21.0
The decile graph below2 illustrates this variability in
wind power generation and shows that the lower decile
changed little between 2013 and 2014, while the upper
decile increased sharply at all times of the day.
%
100
35.8
Wind power output depends on wind conditions and
can thus vary from one day to the next, and over the
course of a given day. Looking at the breakdown of wind
power generation over 2014 by time of day, we see that
10% of the totals recorded at 7:00pm are below 509
MW. This result was more or less the same as in 2013.
However, at that same time of day, 10% of totals are
above 4,027 MW in 2014, implying an increase of almost
300 MW in this threshold compared with 2013.
0
Wind power generation at half-hourly intervals
(average and top/bottom deciles)
Average capacity factor
Maximum capacity factor
Regional breakdown of coverage of
consumption with wind power
MW
5,000
RTE, SER, ERDF and ADEeF jointly publish a “Panorama
of Renewable Electricity”. This document notably
includes a detailed analysis of wind power development
at the level of the administrative regions. Regions that
have built the largest wind farms show the highest
rates of coverage of electricity demand with wind
power. These rates stand at 16% in Picardy and 19% in
Champagne-Ardenne.
4,000
3,000
2,000
22:30
20:30
18:30
16:30
14:30
12:30
10:30
08:30
06:30
04:30
02:30
0
00:30
1,000
Average coverage of consumption
with wind power
Average 2013
Average 2014
Top and bottom deciles
Wind capacity factor
Wind power facilities produced at an average 22.6% of
their capacity in 2014, compared with 23.2% at the end
of 2013.
2 The top decile corresponds to the value that separates
the data between the lowest 10% and the highest 90%. The
bottom decile separates the 90% of lowest values from the
highest 10%.
18
>10%
6-10%
3-6%
0-3%
Photovoltaic
Installed capacity exceeded 500 MW in the four
southernmost regions of mainland France: Aquitaine,
Midi-Pyrénées, Languedoc-Roussillon and ProvenceAlpes-Côte d’Azur. All regions have at least 30 MW of
installed photovoltaic capacity.
Installed capacity
Installed photovoltaic capacity had contracted for two
straight years but began trending upward again in 2014.
With a total 926 MW added, installed capacity climbed
to 5,292 MW of which 338 MW is connected to the RTE
grid and 4,955 MW to the networks of ERDF and local
distribution companies.
Installed photovoltaic capacity
MW
6,000
5,292
5,000
Photovoltaic generation
Photovoltaic generation increased by 27% between
2013 and 2014, ending the year at 5.9 TWh. Monthly
output was higher in 2014 than in 2013 during every
month except December. This growth reflected good
sunlight conditions during the year as well as higher
output at newly installed photovoltaic units. Photovoltaic
generation is variable and fluctuates over a given day,
depending on sunlight, and seasonally, depending on
when the sun rises and sets and on cloud cover.
4,366
4,000
3,727
3,000
Photovoltaic generation
2,584
TWh
2,000
874
1,000
0
1,710
1,143
646 926
5
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
4
0
4
7
61 195
Year-on-year change
5.9
6
Installed capacity at 31 December
4.7
4.1
3
2.1
2
Map of installed photovoltaic capacity
1
0
0
0
0
0
0.2
0.5
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Output peaked on Saturday, 17 May at 1:30 pm at
3,700 MW, representing a capacity factor of 80.3%, the
highest level on record to date.
Power consumption coverage with
photovoltaic power
Photovoltaic generation covered an average 1.3% of
power demand in 2014, up from 1.0% in 2013. On 18
May 2014, at 2:00 pm, photovoltaic power covered 8.5%
of demand, whereas in 2013 coverage had peaked at
7.0%.
More than 500 MW
350-500 MW
200-350 MW
50-200 MW
0-50 MW
19
Installed thermal renewable capacity
800
Average coverage of consumption
with photovoltaic power
1,579
1,346
1,240
1,223
1,030
986
953
1,000
772
1,200
927
1,400
1,041
1,600
1,487
MW
1,800
667
The Panorama of Renewable Electricity provides a
more detailed analysis of growth in the photovoltaic
industry, notably at the level of the administrative
regions. It shows that four regions – Aquitaine, Corsica,
Languedoc-Roussillon and Midi-Pyrénées – cover more
than 3% of their consumption with photovoltaic power
on average, and the Auvergne, Limousin, PACA and
Poitou-Charentes regions boast coverage rates of more
than 2%.
600
400
200
0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Map of installed thermal renewable capacity
>3%
2-3%
1-2%
0-1%
Thermal renewable energy
More than 300 MW
100-300 MW
50-100 MW
Installed thermal renewable capacity increased by 92
MW in 2014, to 1,579 MW. All new facilities installed
during the year were on the distribution grid.
Installed capacity exceeded 100 MW in four regions:
Aquitaine, Provence-Alpes-Côte d’Azur, Rhône-Alpes
and Île-de-France, which had more than 300 MW.
More than half (54.8%) of combustible renewable
energy plants ran on municipal waste. Other fuels used
were biogas, paper waste, wood energy and other solid
biofuels. Municipal waste, wood energy and other solid
biofuels accounted for a larger share of the total than
in 2013.
20-50 MW
0-20 MW
Breakdown of thermal renewable capacity
by fuel source
PAPER WASTE
5.7%
MUNICIPAL
WASTE
54.8%
BIOGAS
20.7%
WOOD ENERGY
AND OTHER
SOLID BIOFUELS
18.8%
20
Hydropower
Installed hydropower capacity was unchanged in 2014.
Hydropower generation remained robust during the
year, totalling 68.2 TWh. This annual total was the
second highest volume in the past decade, with output
notably climbing in the early part of the year, between
January and March. Generation was nonetheless 9.7%
lower than in 2013, which had been an exceptional year
in terms of precipitation with above-average rainfall
across all of France.
Hydropower generation
TWh
80
75.4
70
68.0
63.3
68.2
67.6
63.8
61.9
60
50.3
50
40
2007
2008
2009
2010
2011
2012
2013
2014
Nuclear share of generation
stable, conventional
thermal power down sharply
Nuclear generation capacity did not change in 2014. The
availability of the nuclear power plants was particularly
high, notably starting in the summer of 2014, such that
nuclear power output increased by 3.0%.
Fossil-fired thermal plants represented installed
capacity of 24,411 MW, or just under 19% of the total
for all of France. Installed capacity shrank by 1,296
MW. This decrease was chiefly attributable to the
decommissioning of the Blénod and Cordemais 1 coalfired plants.
Fossil-fired thermal plants provide backup power. Several
factors contributed to the sharp decline in production
in 2014: high hydropower and nuclear generation, rises
in wind and photovoltaic power output, and a decrease
in demand. Power generated by fossil-fired thermal
plants thus ended 2014 39.6% lower. Coal-fired plants
were the most affected, with production falling by
58%, while gas-fired plants only saw a 28% decrease.
Gas-fired plants produced 6.0 TWh more than coalfired units during the year, contrary to 2012 and 2013.
Economic conditions nonetheless remain challenging
for combined-cycle gas (CCG) plants in France where,
like in 2013, some units were taken off line during the
summer months.
Coal and gas-fired generation in France
Weekly hydropower stocks
TWh
%
6
90
5
80
70
4
60
3
50
40
2
30
1
20
10
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51
Week
2011
2012
2013
jan
fe -13
b
m -13
ar
ap -13
m r-13
ay
jun-13
ju 13
au l-13
g
se -13
p
oc -13
no t-13
v
de -13
c-1
jan 3
fe -14
b
m -14
ar
ap -14
m r-14
ay
jun-14
jul -14
au .-14
g
se -14
p
oc -14
no t-14
v
de -14
c-1
4
0
0
Coal
Gas
2014
21
Monthly trends in fossil-fired and renewable generation in 2014
TWh
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
jan
feb
Fossil-fired thermal
mar
apr
Wind power
may
Photovoltaic
In Europe, more than 35 GW of gas-fired capacity has
been mothballed and the number of CCG plant projects
has fallen to a ten-year low.3
Variability of generation
from different sources
jun
jul
aug
sep
oct
nov
dec
Other renewable
Over more than half the year, monthly renewable energy
generation excluding hydropower exceeded output at
fossil-fired thermal power plants. Renewable energy
generation remained high over the year during cold
periods and when greater use was made of fossil-fired
thermal plants.
Monthly coverage of consumption in France with different energy sources excluding nuclear
%
Note to readers: We can see, for instance, that wind power coverage peaked in May, at 16%. During that same month,
coverage exceeded 4.4% half the time.
30
max
25
20
median
15
min
10
5
0
jan
feb
mar
apr
Hydropower
may
jun
Wind power
To assure that demand is met and given the variability
of some energy sources, the breakdown of coverage of
consumption in France changes with seasons and also
over the course of the day.
3 Source: Platts.
22
jul
aug
Photovoltaic
sep
oct
nov
dec
Other renewable
Because of its modular and seasonal nature, hydropower
generation can cover between 5 and 28% of French
consumption, depending on the period.
Another observation is that coverage of consumption
with renewable energy sources excluding hydropower
was higher than coverage with fossil-fired thermal
generation over half of the year.
The ratio was reversed in October, when fossil-fired
thermal generation covered up to 17% of consumption.
Lastly, wind power output can vary from day to day and
over the course of a given day. Coverage of consumption
with wind power peaked at 16% in May, and held at 0.1%
or more during each month of the year.
Monthly CO2 emissions
not including own consumption
Millions of tonnes (Mt)
6
5
4
3
CO2 Émissions
2
1
2013
2014
Average daily CO2 emissions curves
not including own consumption
kg/MWh
60
50
40
30
20
March
June
August
23:30
22:30
20:30
18:30
16:30
14:30
12:30
10
0
4 CO2 emission factors have been refined and historical data
re-updated accordingly. They only represent CO2 emissions
generated by the consumption of the primarily fuel source.
The different generation technologies contributed to CO2
emissions as follows:
- 0.96 t/MWh for coal-fired units;
- 0.67 t/MWh for oil-fired units;
- 0.46 t/MWh for gas-fired units;
- 0.98 t/MWh for other thermal power plants (biogas, waste,
wood energy and other solid biofuels).
These rates are calculated based on emission factors in g/
CO2 per kWh of thermal energy as reported by the Centre
Interprofessionnel Technique d’Etude de la Pollution
Atmosphérique (Inter-professional Technical Centre for Studies
on Atmospheric Pollution - CITEPA) and on RTE’s estimate of
output between kWh of thermal energy and kWh of electricity.
sep oct nov dec
In 2014, monthly CO2 emissions were consistently lower
than in the same months in previous years. However,
these values can vary by a factor of up to seven or
eight within a given month. In October for instance,
CO2 emissions fluctuated between 12 kg/MWh and
91 kg MWh. The profile of CO2 emissions over the course
of a day in winter shows a plateau between 6:00 am and
10:00 pm, while emissions in summer are fairly constant.
10:30
Hydropower
Wind power
Photovoltaic
Other energy sources
Of which renewable
32.2
27.2
19.0
0.8
7.4
5.0
3.5
jul aug
2012
08:30
Of which Coal
Oil
Gas
Other
19.0
13.6
8.0
0.7
4.9
5.4
3.9
2013
Average 2008-2011
06:30
Total
Nuclear
2014
feb mar apr may jun
04:30
CO2 emissions (millions of tonnes)
jan
02:30
CO2 emissions resulting from own consumption added
approximately 5.0 Mt to total emissions. These emissions
are included in the carbon footprint assessments of the
industrial sites in question.
0
00:30
The decline in CO2 emissions observed in 20144 reflected
the sharp drop in fossil-fired thermal generation, which
was in turn due to mild winter temperatures and high
availability rates for the nuclear power plants. As
such, not taking into account own consumption, CO2
emissions totalled 19.0 Mt, for a 41% decline. Moreover,
the increase in the share of gas-fired versus coal-fired
generation offset emissions stemming from the increase
in thermal renewable generation.
October
23
The transmission grid corrects imbalances between
generation and consumption
The map opposite matches electricity generation
against consumption in each of the French regions in
2014. Because generation facilities are rarely located
in the geographic areas where consumption is highest,
there are major discrepancies between regions’ ability
to cover all of part of their consumption with “local”
generation. Some regions like Brittany, Pays-de-la-Loire,
Île-de-France, Burgundy and Franche-Comté consume
five times as much power as they produce, while others
- Centre, Champagne-Ardenne, Upper Normandy,
Rhône-Alpes and Lorraine – produce twice as much as
they consume. These five regions alone are home to
70% of France’s nuclear power capacity.
Coverage rates can vary from one year to the next,
depending on weather events and changes in installed
capacity in given regions. For instance, the coverage
rates of Pays-de-la-Loire and Franche-Comté declined
between 2013 and 2014. This was due to the decrease in
fossil-fired production in these regions, and to weather
that was not conducive to hydropower generation in
Franche-Comté.
The grid allows electricity to move between the regions
to guarantee the security and safety of the power
system.
24
Generation/consumption ratio in 2014
More than double
150% to 200%
120% to 150%
Equivalent
50% to 80%
20% to 50%
Less than 20%
20 TWh
<20 TWh
<10 TWh
Part 3
Consumption
declining
in Europe
25
Consumption declining in Europe
All data presented in this chapter are drawn from
ENTSO-E2 and are calculated on a year-on-year basis.
The data are for the period between July 2013 and June
2014, and changes are calculated relative to the July
2012 to June 2013 period.
Gross consumption lower in
most countries
Gross annual electricity consumption declined in a large
majority of ENTSO-E member countries. Consumption
notably contracted by more than 4% in Germany. The
trend in France was similar. Spain only saw a moderate
decrease of around 0,7%, but consumption in Italy and
Switzerland ended the year down by more than 2.4%.
All in all, annual electricity consumption in ENTSO-E
member countries was down 1.5% relative to the 20122013 period, representing a decrease of around 50 TWh,
equivalent to annual consumption in Greece.
Annual trend in power consumption
Increase of > 4%
Increase of 0.5 to 4%
Flat ± 0.5%
Decrease of 0.5 to 4%
Decrease of > 4%
Data not available
Calculated over the July 2013 to June 2014 period
versus 12 previous months
2 ENTSO-E: European Network of Transmission System
Operators for Electricity. This association brings together 41
European transmission system operators (TSOs), including
RTE. At this writing, data for Great Britain do not cover the
entire country.
26
This downward trend is attributable to the combined
effects of the economic crisis and energy efficiency
measures, and also to the fact that temperatures were
more favourable in the 2013-2014 period. This was
notably the case in France, where the sharp contraction
in annual power demand reflected the high degree of
sensitivity of demand to temperatures.
France, Germany, Spain, Italy
and Great Britain together
home to 60% of European
power generation
Between 2013 and 2014, Europe produced 3,304 TWh
of power, or about 1.4% less than in 2012-2013, due
to a decrease in power demand. France and Germany
alone accounted for almost a third of total generation in
ENTSO-E member countries.
Countries’ share of total ENTSO-E generation
More than 15%
5 to 15%
3 to 5%
Less than 3%
Electricity generated from renewable energy sources
excluding hydropower continued to increase. It
accounted for 14.4% of total annual consumption at the
level of ENTSO-E in the 2013-2014 period.
Coverage of consumption with wind power
More than 15%
5 to 15%
3 to 5%
Less than 3%
Data not available
Coverage of consumption with
photovoltaic power
Photovoltaic generation covered between 5 and 8% of
consumption in Germany, Spain, Italy and Greece. The
average for ENTSO-E as a whole was close to 2.8%.
Coverage of consumption with hydropower
More than 40%
20 to 40%
5 to 20%
Less than 5%
Data not available
Coverage of consumption with
fossil fuel energy
More than 5%
2 to 5%
Less than 2%
Data not available
More than 70%
40 to 70%
15 to 40%
Less than 15%
27
Wind power covered between one fifth and one third
of annual consumption in three countries: Denmark,
Spain and Portugal. In Spain, wind power covered
approximately 21% of consumption, compared with an
average coverage rate of 7.7% in the ENTSO-E area.
France still exports more
than any other European
country
Hydropower covers more than 50% of annual consumption
in Austria, Switzerland, Iceland and Montenegro. In
Norway, production actually exceeded consumption in
2013-2014, making exports to neighbouring countries
possible, though other types of generation may be
called upon to assure that power demand is covered
continuously over the year.
Between 2013 and 2014, total cross-border physical
exchanges between ENTSO-E countries balanced out.
France, Germany and the Czech Republic showed the
highest exports and Italy the highest imports. France
and Germany notably saw their export balances increase
by about 10 TWh relative to the 2012-2013 period.
Lastly, fossil-fired plants covered an average 42% of
annual consumption in ENTSO-E countries. The share
was above 61% in Germany. Coverage in France was
closer to 7% due in part to the preponderance of nuclear
power.
Indeed, nuclear power still covers about 85% of annual
power consumption in France. Belgium and Slovakia also
showed coverage rates of more than 50% for nuclear
power in 2013-2014, whereas almost half of ENTSO-E
member countries no longer have any nuclear plants in
service.
The configuration of individual results by country was
stable relative to 2013 with the exception of Slovakia,
which had an export balance in 2012-2013 but an import
balance in 2013-2014.
Sum of physical flows
S < -40 TWH
-40 TWH ≤ S ≤ -15 TWh
-15 TWh ≤ S ≤ 0 TWh
0 TWh ≤ S < 15 TWh
15 TWh ≤ S < 40 TWh
S ≥ 40 TWH
Not interconnected
Coverage of consumption with nuclear power
More than 60%
30 to 60%
0 to 30%
0%
Import and export capacities available for electricity
exchanges, known as net transfer capacity (NTC), are
calculated and published jointly by system operators.
Their level depends upon the characteristics of
interconnector lines, their availability, and internal
constraints on the power grids of each country.
28
Max NTC for exports
Max NTC for imports
More than 12 GW
7 to 12 GW
3 to 7 GW
Less than 3 GW
Not interconnected/data not available
Calculated for the July 2013 to June 2014 period
Centrally-located countries have the highest maximum
NTC (Max NTC) values for imports and exports, since
they are situated at the heart of exchanges. Examples
include France and Germany, which have max NTCs of
more than 10 GW in both directions. Sweden also has a
max NTC of more than 9 GW for imports and exports.
There can be differences, however, between the max
NTCs for imports and exports in a given country. One
example is Italy, where the NTC for imports is twice as
high as for exports.
FRANCE HAS THE HIGHEST
TEMPERATURE SENSITIVITY IN
EUROPE
A country’s electricity consumption is largely dependent
on its temperature sensitivity. In winter, when electric
heating is switched on, consumption increases as
temperatures decrease. It is estimated that in France,
power demand increases by about 2,400 MW with each
degree Celsius drop in winter temperatures. Demand
can increase when temperatures rise in the summer
mainly because of air conditioning.
This sensitivity of power consumption to temperatures
can be graphically visualised by representing daily
demand as a function of the average daily temperature
in the country. Non-working days have been stripped
out, as have the Christmas holidays and the month of
August, because demand is significantly lower at these
times for obvious reasons not related to the weather.
Demand varies widely from one country to the next,
though the phenomenon of temperature sensitivity in
winter is always visible: when it is cold, consumption
increases as temperatures drop.
29
This phenomenon is the most noticeable by far in France;
as a first approximation, temperature sensitivity is 2.5
times higher in France than in Great Britain, 4.5 times
as high as in Germany and five times higher than in Italy
and Spain.
Daily consumption based on temperatures
TWh
1.8
In southern countries (Italy and Spain), the use of air
conditioning when temperatures are higher is also
visible.
1.6
1.4
1.2
1.0
0.8
0.6
-5
0
5
10
15
20
25
Average daily temperature in the country (°C)
France
Great Britain
Germany
Spain
Italy
On 5 January 2015, TSOs adhering to ENTSO-E began publishing fundamental data about the European electricity
market on a joint platform called the Electricity Market Fundamental Data Information Platform, or EMFIP. This new
platform, which complies with the EU Transparency regulation, is a big step towards harmonising power system data
published across Europe and assuring that it is complete.
30
Part 4
Market prices
trending lower
across all
of Europe
31
Market prices trending lower across all of Europe
Average spot prices on power exchanges in 2014 and change vs. 2013
Nord Pool
€ 29.6 /MWh (-22%)
Great Britain
€ 52.2 /MWh (-12%)
Netherlands
€ 41.2 /MWh (-21%)
Belgium
€ 40.8 /MWh (-14%)
Germany
€ 32.8 /MWh (-13%)
France
€ 34.6 /MWh (-20%)
Switzerland
€ 36.8 /MWh (-18%)
Italy
€ 52.1 /MWh (-17%)
Spain
€ 42.7 /MWh (-5%)
Sources: European power exchanges (for Nord Pool: system price)
Average annual spot prices on power exchanges
contracted sharply across all of Western Europe in 2014.
This downtrend was fuelled by declines in demand
in all countries, reflecting particularly mild weather
conditions. Plummeting fossil fuel prices (oil, gas and,
to a lesser degree, coal) also played a part. In France,
which relies less on these fuels for power generation, a
very high availability rate for nuclear power plants put
additional downward pressure on prices.
Wholesale electricity prices in France remained among
the lowest in Europe. The average gap with German
prices narrowed and the rate of convergence between
prices in France and Germany was of the same order of
magnitude as in 2013. French prices were particularly
low during the summer and held below those of all other
countries most of the time. Prices were higher in Belgium
than in France due to unscheduled shutdowns of several
nuclear power plants there. The rate of convergence
between prices in France and its neighbouring countries
thus decreased.
32
Price convergence within the CWE area*
France alone
25.8%
BE PRICE = DE = FR = NL
18.6%
BE PRICE = DE = FR
5.0%
DE PRICE = FR
27.7%
BE PRICE = FR
* Central West Europe region including France, Germany,
Belgium and the Netherlands
22.9%
Two new extensions for market
coupling in 2014
The integration of European power markets took
major steps forward in 2014 with the extension of
price coupling to the North West Europe (NWE)
region on 5 February and then to the Iberian Peninsula
on 14 May. The price coupling of day-ahead markets
makes a significant contribution to the economic
optimisation of the European power system.
November 2006
November 2010
Same price zone as Germany
February 2014
Via Sweden exclusively
(SwePol subsea cable)
May 2014
Sweden
2015
Norway
Project phase
It creates a single trading area, and therefore zones
with identical prices when interconnection capacities
do not limit cross-border flows. The convergence
observed on the morning of Thursday, 15 May was
remarkable: prices were exactly the same from
Portugal all the way to Finland.
Prices within coupled area on
Thursday 15 May 2014, 6-7:00 am
Gap with French prices
NO4
Price > FR price
0
Price < FR rpice
SE1
NO5
Finland
NO2
Great Britain
France
LV
LT
€ 41.57 /MWh NL
Poland
BE
€ 38.64 /MWh
FR
Austria
Switzerland
EE
SE4
DK2
GB
Netherlands
Germany
SE3
DK 1
Latvia
Lithuania
Belgium
FI
NO1
€ 23.33 /MWh
Estonia
Denmark
SE2
NO3
PL
DE
€ 35.77 /MWh
AT
Slovenia
PT
Portugal
Italy
Spain
ES
Exports up sharply
Overview of contractual trades in 2014 (TWh)
Difference between physical and
contractual trades
Great Britain
Contractual trades between countries are carried
out based on commercial transactions between
market players. Physical exchanges correspond to the
electricity actually carried over interconnector lines
directly interlinking countries.
0.8
17.4
Belgium
0.8
15.9
7.3
Total France
13.2
Exports 92,4
Imports 27,3
Balance 65,1
25.5
Switzerland
9.1
2.9
Spain
19.8
6.5
0.5
Germany
As such, on the France–Germany border, a commercial
import programme might be “offset” by significant
exports to Belgium, Italy or Switzerland, though from
a physical standpoint the power will be carried part of
the way from France to Germany.
For a given country, the balance of physical exchanges
over all of its borders and the balance of contractual
trades with all of its neighbours are identical.
Italy
33
France showed an export balance of 65.1 TWh in 2014,
the highest level since 2002.
Annual contractual trades
In terms of hourly power demand averaged over each
month, export balances exceeded 5 GW throughout the
year, including in winter, thanks to the competitiveness
of French prices.
TWh
100
80
60
France was in an import situation for about 30 hours
during the year, spread over 11 days.
40
No full day ended with net energy imports.
20
0
-20
No. of days with import balance
on contractual trades
-40
Days
-60
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Exports
Imports
Export balance
Monthly contractual trades in 2014
TWh
180
160
140
120
100
80
60
40
20
0
11
0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
10
No. of days with import balance in power terms
over at least one-hour period
8
No. of days with import balance in energy terms
6
4
2
No. of days with import balance on contractual
trades per month in 2014
0
Days
5
-2
4
-4
jan feb mar apr may jun jul aug
Exports
Imports
sep oct nov dec
3
Export balance
2
1
0
No. of days with import balance in power terms
over at least one-hour period
No. of days with import balance in energy terms
34
Germany
Capacity and daily exchanges between
France and Germany in 2014
Monthly exchange balances with Germany
MW Export
4,000
TWh
1.0
3,000
2,000
0.5
1,000
0.0
0
-1,000
-0.5
-2,000
-1.0
-3,000
-1.5
-4,000
-2.0
jan
feb mar apr may jun
2013
Import
jan
feb
mar
apr may
jun
jul
aug
sep
oct
nov
dec
Exchange balance (daily average)
Exchange capacity (NTC as a daily average)
jul aug sep oct nov dec
2014
Comparison of trends in exchange balance on Franco-German border and wind
and photovoltaic generation in Germany
Exchanges (MW)
4,000
Generation (MW)
40,000
3,000
30,000
2,000
20,000
1,000
10,000
0
0
-1,000
-2,000
-3,000
-4,000
Monday 2014-03-10
Exchange balance
Tuesday 2014-03-11
Wednesday 2014-03-12
Wind power in Germany
France was a net importer from Germany on the whole in
2014. However, exchanges were more balanced, ending
the year with an import balance of 5.9 TWh versus 9.8
TWh in 2013 due to relatively low prices in France.
Exports were notably robust in July and August, and
imports were lower in the first four months of the year.
Renewable energy generation in Germany had a
significant impact on reversals of cross-border energy
flows with France. For instance, analysis of hourly trends
in the exchange balance with Germany in relation to the
amount of photovoltaic and wind power injected into
the German grid during a sunny week in March helps
illustrate the influence these variable sources have on
the direction of flows.
The saturation of interconnections between France
and Germany was slightly lower than in 2013, but still
remained at close to 50%.
Thursday 2014-03-13
Friday 2014-03-14
Wind + photovoltaic power in Germany
Hourly periods during which France-Germany
interconnection was saturated a day ahead
%
60
50
40
30
20
10
0
2009
Exports
2010
2011
2012
2013
2014
Imports
35
Belgium
Trading with Belgium was greatly impacted by the
unscheduled unavailability of nearly half of Belgian
nuclear capacity. The country had experienced similar
problems between mid-2012 and mid-2013. The
Tihange 2 and Doel 3 reactors were shut down on 26
March 2014 to conduct safety tests, and then on 4
August Doel 4 was taken offline and was only restarted
on 19 December. As of 31 December 2014, two reactors
were still not back in service.
Belgium thus did without as much as 3 GW of generation,
or up to a third of its capacity excluding renewables.
During the time the three reactors were offline, Belgium
showed a very high net import balance. Export capacity
from France to Belgium was saturated most of the time
and the Netherlands exported to Belgium.
France’s export balance with Belgium increased to 16.5
TWh from 12.9 TWh in 2013.
RTE assessed the impact the shutdown of the three
Belgian nuclear reactors had on the French power
system. Its analysis showed that during the winter of
2014-2015, the shutdowns in question put downward
pressure on operating margins in France, though they
remained high enough to meet safety standards.
Monthly exchange balances with Belgium
TWh
2.0
1.5
1.0
0.5
0.0
-0.5
jan
feb mar apr may jun
2013
jul
aug
sep oct nov dec
2014
Electricity trading in Belgium in 2013 and 2014 (daily averages)
MW
4,000
Second shutdown of
Doel 3 and Tihange 2
Restarting of Doel 3 and Tihange 2
Shutdown of Doel 4
Restarting
of Doel 4
Exports from Belgium to France and the Netherlands
3,000
2,000
1,000
0
-1,000
-2,000
-3,000
Imports to Belgium from France and the Netherlands
-4,000
jan
feb mar apr may jun
jul
aug sep
oct
nov dec
jan
feb mar apr may jun
2013
Balance Belgium / France
36
Balance Belgium/Netherlands
jul
aug sep
2014
Total balance
oct
nov dec
Spain
Monthly exchange balances with Spain
France exported to Spain 69% of the time in 2014, up from
62% in 2013. The export balance doubled to 3.6 TWh from
1.7 TWh in 2013.
TWh
1.0
0.8
Prices were extremely volatile in Spain due to the high
percentage of variable renewable sources in the energy
mix, which exceeded 50% during some months. When
renewable generation in Spain peaks, local prices
plummet, and fall below French prices; in this case flows
are reversed, and France imports electricity from the
Iberian Peninsula.
0.6
0.4
0.2
0.0
-0.2
-0.4
Interconnection capacity was saturated 67% of the time 45% of the time in the France-Spain direction and 22% of
the time going the other way. Exchange capacity between
the countries will double in 2015 when the new BaixasSanta Llogaia line (see Part 5) interconnection comes into
service.
-0.6
-0.8
jan feb mar apr may jun
2013
2014
Capacities and daily exchanges between France and Spain in 2013 and 2014
MW
3,000
Export
2,000
1,000
0
-1,000
-2,000
-3,000
Import
jan
feb mar apr may jun
jul
aug sep
oct
nov dec
2013
jan
feb mar apr may jun
jul
aug sep
oct
nov dec
2014
Trend in wholesale electricity prices in France and Spain in relation to renewable generation in Spain
Price in €/MWh
TWh
100
20
18
50
16
14
0
12
10
8
6
4
2
0
jan
feb mar apr may jun
jul
2013
Photovoltaic
Hydro
Wind
aug sep
oct
nov dec
jan
feb mar apr may jun
jul
aug sep
oct
nov dec
2014
Average monthly spot price (base-load) in France
Average monthly spot price (base-load) in Spain
Sources: www.ree.es (figures as of 20/01/2015) for generation data, EPEX Spot and OMIE for prices
37
Switzerland
Great Britain
Monthly exchange balances with Switzerland were again
dominated by exports; they rose between January and
August and dropped in the latter months of the year.
The total annual balance was 16.5 TWh in 2014, the
same as in 2013.
The annual export balance with Great Britain rose sharply
to 15.2 TWh. France-England interconnections showed
good availability during the year. Interconnection
capacity was used for exports during more than 99%
of the hours of the year and saturated about 90% of the
time.
Monthly exchange balances with Switzerland
Monthly exchange balances with Great Britain
TWh
TWh
2.5
1.5
2.0
1.2
1.5
0.9
1.0
0.6
0.5
0.3
0.0
2013
jul aug
sep oct nov dec
2014
2013
Capacities and daily exchanges between
France and Switzerland in 2014
MW
4,000
0.0
2014
France and Great Britain in 2014
Export
MW
3,000
4,000
2,000
3,000
1,000
2,000
0
1,000
-1,000
0
-2,000
-1,000
-3,000
-2,000
Import
-3,000
-4,000
jan feb mar
Export
apr may jun
jul aug
sep oct nov dec
-4,000
Import
jan feb mar
apr may jun
jul aug
sep oct nov dec
38
The balancing mechanism
Italy
Exchanges with Italy were largely dominated by exports
with a balance of 19.3 TWh, or 3.9 TWh more than in
2013. Export capacity toward Italy was increased by
400 MW in October thanks to the strengthening of the
Alpine networks. During the spring and summer, Italy
must limit its imports on days when demand is low.
Indeed, given the significant photovoltaic capacity in
place, it must keep in operation a number of thermal
plants that can modulate their output and assure the
stability of the power system.
Monthly exchange balances with Italy
TWh
TWh
6
2
2.0
0
1.5
-2
1.0
-4
0.5
-6
0.0
2013
2014
France and Italy in 2014
4,000
Volumes balanced on the balancing mechanism
4
2.5
MW
The balancing mechanism allows RTE to modulate
generation, consumption and exchange levels to
assure that electricity supply and demand are always
balanced. The mechanism involves the selection of
offers submitted by Balancing Actors, based on their
merit order.
Export
3,000
2,000
-8
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Load shedding
Cross-border exchanges
Nuclear
Hydro
Total balancing volumes declined between 2013 and
2014. Energy volumes activated upwards were notably
the lowest on record since the mechanism was created.
The use of fossil fuel capacity declined sharply.
Balancing volumes represented less than 1% of the total
business volumes of balance responsible entities.
1,000
0
-1,000
-2,000
-3,000
-4,000
Import
39
ACTIVITIES OF THE BALANCE
RESPONSIBLE ENTITIES
Average cost of balancing transactions
€/MWh
120
The balance responsible entity system allows consumers,
generators, suppliers and traders to conduct all types of
commercial transactions in the electricity market. Each
balance responsible entity creates an activity portfolio
and agrees to settle the costs resulting from imbalances
between generation and consumption within it, as
recorded after the fact.
100
80
60
40
20
0
-20
-40
-60
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Upward (payments from RTE to actors)
Downward (payments from actors to RTE)
There were 192 balance responsible entities with valid
contracts in 2014, or 17 more than in 2013. Of these, 134
were actually active, and for 26 physical injections and
withdrawals on the grid represented at least 10% of their
total business.
Transactions conducted by balance responsible
entities on markets
This average cost includes any start-up costs
TWh
600
500
Situations of tight supply
(number of half days)*
400
300
70
200
60
100
50
0
40
2010
2011
2012
2013
2014
RE-BRE NEB
On the exchange
VPP
ARENH
Purchases of PTS losses (outside the exchange)
30
20
10
0
2007
2008
Upward
2009
2010
2011
2012
2013
2014
Downward
* Supply is considered to be tight from a supply-demand
balance standpoint when RTE generates one or more
messages about insufficient offers on the balancing
mechanism (alerts or degraded mode) so actors will submit
additional offers.
Supply was rarely tight in the French power system in
2014.
40
An overall increase in transactions conducted by balance
responsible entities was observed, with:
•
A 10% increase in the volume of party-to-party
transactions (block exchange notifications, or NEB)
versus 2013.
•
A 15% increase in volumes traded on the power
exchange. This rise was notably visible on the
day-ahead market starting in April 2014: weekly
trades reached an all-time high in the week of 1 to 7
December 2014.
•
An 11% rise in ARENH volumes to 71 TWh. This
increase was primarily attributable to the fact that
since 1 January 2014, energy delivered to offset
system operator losses has been eligible for inclusion
in the ARENH mechanism. On the other hand, the
volumes requested at the end of 2014 for the first half
of 2015 were down sharply.
• Virtual Power Plants (VPP) continue to be phased
out gradually pursuant to the European Commission
decision of 30 November 2011. These products only
represented 3.4 TWh, down from 8.5 TWh in 2013,
and should be eliminated altogether in 2015.
Intra-day transactions conducted by balance
responsible entities
TWh
20
Purchases and imports
15
The development of new load shedding and load
curtailment capacity is continuing.
Load shedding allows more flexibility in managing the
system and is an additional asset when it comes to
maintaining the supply-demand balance and assuring
security in the French power system at all times. Since
2003, load shedding capacity can be offered on the
balancing mechanism and, since 2014, it can also be
requested directly by a market player.
Load shedding involves consumers cancelling or
postponing all or part of their consumption in response
to a signal.
10
5
0
-5
-10
-15
New load shedding capacity
being developed
Sales and exports
2010
2011
2012
2013
2014
NEB (downward re-declarations)
NEB (upward re-declarations)
Exchange
Import or export
Balance responsible entities are increasingly using
intraday mechanisms, notably on interconnections
(+20%) and the exchange (+17%).
There are two main categories of load shedding that
contribute to the supply-demand balance:
• Industrial load shedding, when production stops at
one or more industrial sites.
•
Distributed load shedding , which corresponds to
the aggregation by an aggregator of individual load
shedding actions involving smaller demand volumes,
all carried out at the same time by residential or
professional customers.
RTE uses a series of calls for tenders to contract
industrial or distributed load shedding capacity that
can be activated on the balancing mechanism. Through
these contracts, players commit to offer to shed or shift
loads under very specific conditions, in exchange for
which they are compensated:
• Since 2008, RTE has been contracting load shedding
capacity with balancing actors to guarantee the
availability of these offers on the balancing mechanism.
Volumes des effacements sur le mécanisme
d’ajustement
GWh
25
20
15
10
5
0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
41
• Since 2011, RTE has been contracting load shedding
capacity that can be activated on very short notice
for the rapid and complementary reserves. Contracts
resulting from the latest call for tenders have been in
effect since 1 April 2014.
Thanks to these tenders, RTE had up to 1,200 MW of
load shedding capacity at its disposal in 2014, capacity
it could activate under specific conditions.
Given that upward balancing volumes declined in 2014,
the amount of load shedding capacity activated on the
balancing mechanism decreased, falling to 12 GWh
(-39% versus 2013).
Load shedding capacity representing 100 MW or more
was activated on 14 days over the year, and a maximum
of more than 500 MW was recorded on 15 April.
However, offers submitted increased sharply in 2014:
though little use was made of load shedding capacity
during the year, it contributed to the power system’s
margins.
Maximum load shed each day on the balancing mechanism in 2014
MW
600
500
400
300
200
100
0
jan
feb
mar
apr
may
jun
jul
aug
sep
oct
nov
dec
Minimum, mean and maximum load shedding capacity available on the balancing mechanism per week
MW
1,200
1,000
800
600
400
200
0
jan feb mar apr may jun jul aug sep oct nov dec jan feb mar apr may jun jul aug sep oct nov dec jan feb mar apr may jun jul aug sep oct nov dec
2012
Minimum capacity offered
42
2013
Mean capacity offered
2014
Maximum capacity offered
NEBEF
Since 1 January 2014, the new “NEBEF” mechanism
(Block Exchange Notification of Demand Response)
has allowed actors to realise value on load shedding
capacity directly on the market.
The new mechanism was used for the first time when
RTE was notified of 30 MW of load shedding on 8
January 2014 for two hours. RTE verifies after the
fact that the loads shed correspond to the schedules
submitted by actors. The monthly error (weighted by
volumes declared by actors) typically ranges between
10% and 20%.
Monthly load shedding volumes submitted
to the NEBEF in 2014
MWh
120
100
80
60
RTE creating new market
mechanisms
From the beginning, RTE has been working with market
players to create mechanisms that facilitate the opening
of the French electricity market and its integration within
Europe.
In 2014, market coupling expanded to Great Britain and
the Nordic countries, and then to the Iberian Peninsula.
The Italian market will be coupled in the first half of 2015.
The areas coupled will subsequently represent more
than 84% of total electricity consumption in Europe.
Due to the exceptional situation in Belgium during the
2014-2015 winter, the TSOs participating in the project
opted to postpone flow-based power market coupling,
initially scheduled for November 2014, until the spring
of 2015. Flow-based coupling will involve introducing a
new method of calculating and allocating power trading
capacity for the CWE region. With this algorithm, crossborder flows will be aligned as closely as possible to the
physical capacities of the network.
40
20
0
jan
feb mar apr may jun
jul
aug sep oct nov dec
Over the year, a total of 347 MWh of load shedding
was submitted to the mechanism by five actors. As of
31 December 2014, 12 actors had contracts with RTE to
participate in the NEBEF mechanism.
Total load shedding on the NEBEF between
January and November 2014, half-hourly basis
MWh
40
30
20
10
0
0h
2h
4h
6h
8h
10h
Load shedding scheduled
12h 14h
16h 18h
20h 22h
Load shedding completed
Loads are usually shed when spot prices are highest and
in situations where supply is particularly tight.
43
Part 5
RTE is investing
today in the grid
of the future
44
RTE is investing today in the grid of the future
RTE improving the quality of
electricity
Equivalent outage time lower than in 2013
Equivalent outage time (temps de coupure équivalent TCE) is an indicator used to measure the quality of the
electricity supplied by RTE. It is calculated as a ratio
between:
• Total energy not served during times when no power is
delivered to RTE’s distributor and industrial customer
sites (excluding the energy and rail sectors);
• The average power served annually by RTE to these
same customers.
In 2014, the equivalent outage time for RTE customers
was 2 min 46 sec, excluding exceptional events. This
result reflects the actions RTE has undertaken to improve
the quality of the electricity supplied to its customers.
Further actions must be taken to move within the 2 min
24 sec limit set out in the incentive regulation.
Only one event was classified as exceptional in 2014,
representing an additional equivalent outage time of
less than 2 sec. It occurred when power was cut to three
lines while fire services intervened in a fire zone under
the lines. It is also worth noting that three events alone
accounted for more than 38% of total equivalent outage
time3.
Outage frequency lower despite high
lightning density
Since 2013, outage frequency has been factored into
the incentive regulation created by CRE to encourage
continuity of supply. It corresponds to the average
number of short outages (between 1 sec and 3 min)
and long outages (more than 3 min) experienced during
the year by RTE’s distributor and industrial customers
(excluding the energy and rail sectors).
In 2014, outage frequency excluding exceptional events
was 0.46, which was lower than in 2013. This result
was well within the 0.6 limit set out in the incentive
regulation, and was even below the average of the past
ten years (0.54).
Note that the exceptional event recorded during the
year had a negligible impact on outage frequency
(< 0.001).
Outage frequency and lightning density
Number of outages/site
Number of impacts/km2
1.2
1.2
1.0
1.0
0.8
0.8
0.6
0.6
Equivalent outage time
0.4
0.4
Minutes and seconds
0.2
0.2
20
0.0
0.0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
15
Short outages (due to exceptional events)
Short outages (excluding exceptional events)
10
Long outages (due to exceptional events)
4:26
5
2:04
Long outages (excluding exceptional events)
Lightning density
3:18
2:48
1:44 2:17 3:01 2:46
0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Excluding exceptional events
Due to exceptional events
3. The incentive regulation for electricity quality is based on
two key indicators:
- Equivalent outage time;
- Outage frequency.
A financial bonus-malus system is applied based on the results
observed during the year.
45
Of the numerous factors that determine outage
frequency, lightning density has a major impact on the
number of short outages observed during the year. In
most cases, the regions that are hit by lighting the most
show a high frequency of short outages. Conversely, in
regions where there is relatively little lightning, short
outage frequency is lower.
In 2014, lightning density reached 0.97 strikes per km²
across France as a whole.
most of RTE’s infrastructure is located in agricultural
areas (70%) or wooded regions (20%), and some 15,000
km of power line corridors cross through protected
natural areas.
Protecting and encouraging the development of
biodiversity are the cornerstones of RTE’s environmental
policy. Its commitment is recognised as part of the
“2011-2020 National Strategy for Biodiversity” by the
Ministry for Ecology, Sustainable Development and
Energy.
In 2014, RTE set aside 582 hectares of land for
biodiversity conservation.
Lightning density
Short outage frequency
Loss rate stable in 2014
Line losses occur when electricity is being carried
from generation to consumption sites, and loss
volumes depend on the transmission distance and the
characteristics of the grid. Nearly 80% of these losses are
due to the Joule effect on high and extra high voltage
lines. Other effects contribute as well, notably when
current passes into transformer substations.
Losses are a function of the intensity moving through the
infrastructure, and increase when consumption is higher.
RTE works to minimise losses to reduce the impact of
electricity transmission on the environment, by optimising
the distance over which electricity travels and taking full
advantage of the flexibility it has in operating the grid.
Lightning density (lightning strikes per km2 and per year)
LD < 0.60
0.60 < LD < 1.08
LD > 1.08
Short outage frequency (number of outages between 1 sec
and 3 min per customer site per year)
SOF < 0.20
0.20 < SOF < 0.59
SOF > 0.59
RTE standing up for the
environment and biodiversity
RTE is taking action to reduce the environmental impact
of its activities by utilising its resources more efficiently.
In 2004, RTE launched a proactive initiative to reduce
leakage of SF6, a gas with a strong greenhouse effect.
SF6 is currently indispensable to the electrical insulation
of RTE equipment, including substations inside
buildings (Gas Insulated Substations, which are currently
a societal expectation). In 2014, RTE met its target of
reducing emissions to under 5.5 tonnes.
RTE is also forging partnerships to turn its power line
corridors into corridors of biodiversity. The fact is that
46
In 2014, losses reached 10.6 TWh, which corresponded to
2.08% of consumption.
RTE invested close to
€1.4 billion in 2014
In 2014, RTE’s investments within the scope of businesses
regulated by the CRE totalled €1,374 million, of which
€1,243 million was invested in grid infrastructure.
The bulk of these investments corresponded to the
accommodation of renewable energies, the ongoing
construction of the direct current line that will strengthen
the interconnection between France and Spain through
the Eastern Pyrenees, the replacement of conductors
to make flows more secure on the 400 kV line between
Montélimar and Lyon, and bolstering security of supply
to the regions (PACA, Vendée). Moreover, nearly 35% of
investments in grid infrastructure were for replacements
designed to maintain service quality.
RTE investments
M€
1,500
Length of circuits in
service
At 31 December 2013
New
1,200
900
300
0
Overhead Underground
100,674
4,309
689
422
Total
104,983
1,111
Newly added
29
345
374
Replaced
Overhead lines buried
660
0
9
68
669
68
-750
-2
-752
-3
-8
-11
100,610
-64
4,721
412
105,331
348
Scrapped
Other modifications
(length adjustments)
At 31 December 2014
Change 2013-2014
600
Total
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
These investments are being made bearing in mind
that, over the coming years, rising to the challenges of
the energy transition will require more and more effort.
Indeed, the French transmission grid will play a key role
in accommodating new generation sources (including
offshore wind farms), integrating European energy
markets (by strengthening cross-border capacity), and
assuring the operational safety of the networks and
quality of supply to the different consumption areas and
regions.
Underground network
expanded in 2014
With 105,331 km of lines in service, RTE’s network
expanded in 2014, and the length of its underground
lines increased. The length of the overhead circuits
did not change during the year, 2013 having seen the
Cotentin-Maine EHV line go live.
All in all, the network in service was expanded by 348
km in 2014. New underground lines accounted for 345
km, much more than in 2013 (100 km). Lines scrapped or
replaced in 2014 represented a total of 752 km.
New lines
Km
300
250
200
150
100
50
0
20
01
-20
03
20
02
-20
04
20
03
-20
05
20
04
-20
06
20
05
-20
07
20
06
-20
08
20
07
-20
09
20
08
-20
10
20
09
-20
11
20
10
-20
12
20
11
-20
13
20
12
-20
14
RTE has stepped up its investment programme for 2015,
which should be in the region of €1.5 billion. This will
ensure that the structural work planned (direct current
line between France and Italy, through the service
gallery in the Fréjus tunnel, and reconstruction of the
400 kV Charleville-Reims line) can be carried out in
2015. The programme also calls for additional actions to
expand and update the information system.
Besides the Cotentin-Maine line, most new lines are
being built using underground technology.
Underground (90 kV and 63 kV) Sliding average over 3 years
Overhead excluding Cotentin-Maine (400 kV and 225 kV),
Cotentin-Maine line
Also in 2014, 22 new substations were connected, nine
of which were extra high voltage. Examples included the
400 kV Oudon substation, where the Cotentin-Maine
project ends, and the 400 kV Galoreaux substation
in Pays de la Loire. Their purpose is to bolster power
supply to western France and the southern part of Pays
de la Loire.
As regards 225 kV substations, the Saint-Cyr-En-Val
and Tivernon substations in the Centre region, Darcey
in Burgundy and Saintois in Lorraine are all helping
enhance grid security in these regions.
47
Another 55 km of new underground cables, in addition
to the 106 km built for the PACA safety net, were also
brought into service, notably in Lyon and Marseille. In
this case underground technology was required due
to the highly urbanised areas in which the cables were
installed.
Conductor replacement work was also done on 468 km
of 400 kV and 225 kV overhead lines. Examples include
the Chaffard-Coulanges 400 kV line in the Rhône-Alpes
region and several 225 kV lines: Barbuise-Les Fossés in
Champagne-Ardenne, Margeride-Rueyres in Auvergne
and La Mole-Sainte Feyre in Limousin.
New 63 kV and 90 kV lines and
replacements
Ninety per cent of new 63 kV and 90 kV lines were placed
underground in 2014; this rate stabilised during the year
and averaged 92% over the past three years.
In 2014, 252 km of new underground lines were brought
into service, up from 110 km in 2013 and 208 km in 2012.
The most important underground lines commissioned
at these voltage levels were South Hill-Periers in Lower
Normandy, Forges Les Eaux-Neufchatel in Upper
Normandy, Grande Synthe-Ruytingen in Nord-Pas de
Calais, Cantegrit-Mimizan in Aquitaine and DarceyPoiseul in Burgundy.
48
93
80
76
92
81
67
60
57
40
30
20
37
34
29
46
33
20
03
-20
04
03
-20
05
20
04
-20
06
20
05
-20
07
20
06
-20
08
20
07
-20
09
20
08
-20
10
20
09
-20
11
20
10
-20
12
20
11
-20
13
20
12
-20
14
0
-20
These innovative technical solutions will be incorporated
into the safety net planned for Brittany, with its 80 km of
225 kV lines, all underground.
100
02
To enhance security of supply to the region, the PACA
safety net will make it possible to avoid cutting power
to the entire eastern part of the region if the main 400
kV line between Avignon and Nice is down. The BoutreTrans link is almost 65 km long, whereas previously, the
longest 225 kV underground line in France has a length
of 21 km. With these new developments, RTE is pushing
back the limits of the technologies and methods used
until now to build underground electric infrastructure.
%
01
The PACA safety net involves three new 225 kV
underground lines - Biançon-La Bocca, BiançonFréjus and Boutre-Trans – in the Var and Maritime Alps
departments.
Undergrounding rate for 63 kV and 90 kV lines
20
The “PACA safety net” was tested during the last
quarter of 2014. This was the final step before it could
be deployed early in 2015.
Some overhead lines were also partially or totally
undergrounded during the year, including Vitré-Piquage
line in Bréal, Brittany and the Hourtin-Lacanau line in the
Aquitaine region.
20
New 400 kV and 225 kV lines
and replacements
All in all, the portion of the 63 kV and 90 kV lines located
underground continues to rise steadily and represented
6.2% of the existing network in 2014. This rate varies from
one region to the next depending on local population
density, physical geography (flat or mountainous land),
the existence of protected areas, or the additional cost
to the community relative to building overhead lines.
Note that in 2014, 27 km of new 63 kV and 90 kV overhead
circuits were also brought into service and conductors
were replaced along 179 km. Examples of how the grid is
being strengthened include Bellac-Maureix in Limousin,
Barettes-Buquet in Upper Normandy and GueugnonSornat in Burgundy.
Deux nouvelles liaisons
transfrontalières
Two new cross-border lines were commissioned in 2014.
The first connects the Principality of Andorra with a
direct 150 kV link built between Hospitalet (France) and
Grau-Roig (Andorra). The Island of Jersey was already
getting power from the Cotentin via two 90 kV subsea
lines, and a third 90 kV underground connection that is
partially immersed was added. This new cross-border
line guarantees reliable and high-quality power supply
to the Island of Jersey.
RTE already working on the
grid of the future
France-Spain interconnector in the Eastern
Pyrenees
The decision was made to build this fully underground
link between Baixas (near Perpignan, France) and Santa
Llogaia (close to Figueras, Spain) in 2008. This 65 km link
(35 km in France and 30 km in Spain) crosses the Albera
Massif with an 8.5 km tunnel and uses direct current
technology with AC/DC voltage source converters at
each end. With a capacity of 2,000 MW and operating
at 320 kV, the link will double interconnector capacity
between France and Spain from 1,400 MW to 2,800 MW.
This boost in exchange capacity between the countries
will facilitate the further integration of renewable
energies into the European grid.
The construction of the new interconnector between
France and Spain has been entrusted to INELFE, which
is jointly owned in equal shares by RTE and REE.
Construction work on the line has been completed and
the first live tests have just taken place. The latter part
of 2014 and early months of 2015 will be devoted to
various tests on this innovative line.
Accommodating offshore wind power
The renewable energy development plan for France that
resulted from the Grenelle environmental conference
aims to boost annual renewable energy output so that
it can cover at least 23% of final energy consumption
by 2020. One aspect of the plan is the development of
6,000 MW of offshore wind and marine energy capacity
in France by 2020.
Under the contract terms of the first call for tenders,
RTE will act as the contracting authority and project
manager for studies on and the building of connections
between the four production areas in Fécamp (Upper
Normandy), Courseulles-sur-Mer (Lower Normandy),
Saint-Brieuc (Brittany) and Saint-Nazaire (Pays de
la Loire). This project calls for 350 wind turbines
representing combined capacity of 2,000 MW and split
between these four sites.
To connect these different projects, RTE is proposing
the creation of 225 kV double circuit lines, starting out
underwater between the wind farm and the landing
point, and then running underground between that
landing point and the 225 kV substation where it is
earthed. An existing substation can be used or one
can be created under existing lines. The plotting of
these different lines was the subject of a far-reaching
consultation in 2013 and 2014.
In May 2014, the government announced the results
of the second call for tenders for two wind farms with
capacity of 500 MW each, one off the coast of Tréport
in Upper Normandy and one in Noirmoutier-Yeu, in
Pays de la Loire. Both projects went to the consortium
formed by GDF Suez, Areva, Portuguese energy firm
EDP Renovaveis and Neoen Marine, in partnership
with Areva. As with the first tender, RTE is in charge
of connecting the projects. Offshore studies and
local consultations to help determine how they will be
connected will kick off in 2015.
Location of future wind farms
1er tender
LE TRÉPORT
2e tender
FÉCAMP
498 MW
83 turbines
COURSEULLES-SUR-MER
450 MW
75 turbines
LE TRÉPORT
FÉCAMP
SAINT-BRIEUC
500 MW
100 turbines
COURSEULLESSUR-MER
SAINT-BRIEUC
SAINT-NAZAIRE
480 MW
83 turbines
SAINT-NAZAIRE
YEU-NOIRMOUTIER
YEU-NOIRMOUTIER
The contract for these offshore wind farms was awarded
in April 2012 to the Eolien Maritime France (EMF)
consortium formed by EDF Energies Nouvelles, Dong
Energy Power and Alstom for the Courseulles-sur-Mer,
Fécamp and Saint-Nazaire farms and Ailes Marines
SAS – comprising Iberdrola, EOLES-RES SA and Areva
– for the Saint-Brieuc farm. Together, these projects
represent more than 300 wind turbines and capacity of
about 2,000 MW.
49
MAIN NEW CONNECTIONS IN 2014
Power supply to
Boulogne-sur-Mer
AMIENS
CHARLEVILLEMÉZIÈRES
Power supply
to Beauvais
LAON
Power supply
nord Lorraine
ROUEN
SAINT-LÔ
CAEN
PONTOISE
ÉVREUX
Low voltage management
in the northwest
ALENÇON
RENNES
Power supply
to Mayenne
CHARTRES
LE MANS
COLMAR
CHAUMONT
ORLÉANS
AUXERRE
VANNES
BELFORT
VESOUL
Power supply
to Côte d’Or
BLOIS
TOURS
DIJON
NANTES
BOURGES
POITIERS
LONS-LE-SAUNIER
Power supply to Pays de Gex and
Bellegarde area
MOULINS
MÂCON
NIORT
LA ROCHELLE
BESANÇON
NEVERS
Power supply
to Moulins
CHÂTEAUROUX
LA ROCHE-SUR-YON
STRASBOURG
Power supply
to Nancy
ÉPINAL
Power supply
nord Orléans
Power supply
to Tours
ANGERS
NANCY
TROYES
New generation capacity
Orléans
LAVAL
BAR-LE-DUC
Aube
ÉVRY
SAINT-BRIEUC
QUIMPER
CHÂLONSSUR-MARNE
PARIS
VERSAILLES
METZ
Power supply
to Greater Paris
BOURG-EN-BRESSE
GUÉRET
ANNECY
LIMOGES
CLERMONTFERRAND
ANGOULÈME
LYON
Power supply
to Lyon
Power supply to
Clermont-Ferrand
SAINT-ÉTIENNE
TULLE
PÉRIGUEUX
CHAMBERY
GRENOBLE
AURILLAC
LE PUY-EN-VELAY
BORDEAUX
VALENCE
PRIVAS
Power supply
to Bordeaux
GAP
MENDE
CAHORS
RODEZ
AGEN
MONT-DE-MARSAN
MONTAUBAN
Power supply to
Mont-de-Marsan
AUCH
PAU
DIGNE-LES-BAINS
Electrical safety
in the southwest
Power supply to NÎMES
Montpellier
ALBI
MONTPELLIER
TOULOUSE
in the southwest CARCASSONNE
TARBES
FOIX
AVIGNON
NICE
Power supply
to Marseille
MARSEILLE
TOULON
Power supply to
Perpignan
PERPIGNAN
EXISTING GRID
400 kV line
225 kV line
PLANNED ADDITIONS TO GRID
Security of supply
Creation of new lines
Project being considered
Plans to create or adapt substations
Source: Ten-year Network Development Plan
50
Purpose
Line strengthening
High voltage management
Short circuit current control
Grid stability
Combined-cycle gas
Renewable energies
Marine turbines
France-Italy (Savoy-Piedmont)
interconnection
The Savoy-Piedmont project, led by RTE and TERNA,
involves building an underground 320 kV direct current
line between Chambéry and Turin. Completion of this
190 km double circuit underground line will boost
interconnection capacity between France and Italy by
1,200 MW. Construction started on the French side
in 2014 and the interconnector is scheduled to be in
service in 2019.
France-England (IFA2) interconnection
Since 1986, France and England have been
interconnected by the IFA France-England direct
current interconnector with a capacity of 2,000 MW. But
additional transmission capacity has become necessary.
A consultation on the new IFA2 link kicked off in 2014
and it should be in service by 2020.
Running under the sea for 200 km and underground
for about 30 km, the new interconnector will link Lower
Normandy to the central south coast of England. This
direct current, 1,000 MW line will increase exchange
capacity between the two countries. RTE is handling this
project in partnership with National Grid Interconnectors
Limited, a subsidiary of its British counterpart in charge
of developing interconnector capacity.
Power supply to the Haute-Durance
Power is supplied to this region primarily via a single
150 kV line built in 1936 and capable of carrying up to
220 MW of electricity. The Haute-Durance now finds
itself in a vulnerable position, particularly when power
demand peaks in winter. All regional players’ analyses
concur that the energy situation could become critical in
2016, and that the region could need an estimated 250
MW in 2020.
RTE has thus designed a programme that is staggered
over time and divided into six projects. It involves
creating a 225 kV network to replace the existing 150 kV
line and upgrading the 63 kV network (undergrounding,
reconstruction or strengthening). All of this would be
done making maximum use of existing corridors in order
to conserve and even enhance the environment in the
Haute-Durance.
The first two “Declarations of Public Utility” for the
Haute-Durance project have been signed. Work got
under way in September 2014 and the new infrastructure
should be in service in 2020.
Plan to rebuild a 225 kV overhead/
underground line between the Upper
Loire and Loire regions (2 Loires project)
Some major urban and industrial hubs of the Upper Loire
and Loire regions are concentrated between Le Puy-enVelay, Yssingelais and Saint-Étienne. Power is provided
to these areas by a 225 kV line that has been supporting
the region’s industrial and economic growth for almost
70 years. The line was built in 1941 and has now reached
its technical limits.
A “Declaration of Public Utility” was published for the
2 Loires project in the Official Journal in August 2014,
after four years of consultations between RTE and
regional stakeholders (elected officials, government
services, associations, local residents, socioeconomic
representatives, etc.) to determine the best possible
path for the line.
51
MAP OF MAIN PROJECTS
EXISTING GRID
PLANNED ADDITIONS TO GRID
400 kV line
Line strengthening
Security of supply
225 kV line
Creation of new lines
Project being considered
Plans to create or adapt substations
Source: Ten-year Network Development Plan
52
Purpose
High voltage management
Short circuit current control
Grid stability
Combined-cycle gas
Renewable energies
Marine turbines
Glossary
ADEeF: Association of Electricity Distributors
in France.
Adjusted consumption: Power that would
have been consumed if temperatures had
been the same as reference temperatures, and
if there was no 29th day in February for leap
years.
ARENH: Accès Régulé à l’Électricité Nucléaire
Historique, or Regulated Access to Incumbent
Nuclear Electricity: Refers to suppliers’ right to
buy electricity from EDF at a regulated price,
in quantities determined by French energy
regulator CRE.
Balance responsible entity: An electricity
market player that has a contract with RTE
under which it must settle the cost of any
differences between energy injected and
withdrawn, as recorded after the fact, across
the entire portfolio for which it is responsible.
Balancing mechanism: Mechanism designed
to assure that, at any given time, RTE has
sufficient power reserves it can activate if
supply and demand do not balance.
Capacity factor: Ratio between the electrical
energy effectively generated over a given
period and the energy that would have been
produced at nameplate capacity over the
same period.
Coverage rate: Ratio between power
generated and gross domestic consumption at
a given time.
CWE: Central West Europe, region including
France, Belgium, Germany, Luxembourg and
the Netherlands within which electricity market
prices have been coupled since 2010.
ENTSO-E: European Network of Transmission
System Operators for Electricity, which has
34 member countries and 41 transmission
system operator (TSO) members. Its purpose
is to promote important aspects of electricity
policy such as security, renewable energy
development and the power market. ENTSO-E
works closely with the European Commission
and is the backbone of the European electricity
market.
“Equivalent outage time”: Energy not
supplied as a result of customer power cuts
and load shedding, expressed as a ratio to
the total annual power supplied by RTE to its
customers.
ERDF: Électricité Réseau de Distribution
France.
Exceptional events: High impact, low
probability atmospheric phenomena as well as
cases of force majeure.
Generation:
• The “Hydro” category includes all types of
hydropower stations (poundage, run of river,
etc.). Consumption resulting from pumping
at “STEP” (pumped storage stations) is not
deducted from generation.
• The “Nuclear” category includes all nuclear
power plants. Consumption by auxiliary
generator sets is deducted from generation.
• The “Fossil-fired thermal” category
includes fuels like coal, oil and gas.
• The “Thermal renewable” category includes
biogas, paper/paperboard waste, municipal
waste, wood-energy and other solid biofuels.
Gross consumption: Power consumed across
France, including Corsica and factoring in
losses.
Heavy industry: Final customers getting
electricity directly from the transmission
system operator.
Intraday: Refers to electricity trades
conducted on very short notice, almost in real
time.
LDCs: Local Distribution Companies. These
are, along with ERDF, the operators of the
distribution system, intermediaries between
the transmission grid and final customers.
There are approximately 150 LDCs across
France.
Lightning density: Number of times lighting
strikes per year and per square kilometre in a
given region.
Load shedding: Mechanism by which
consumers cancel or postpone all or part of
their power consumption in response to a
signal.
Market coupling: Process by which
electricity supply and demand are matched
across different markets, within the limits
of the interconnection capacity between
these markets. An algorithm simultaneously
determines prices and implicitly allocates
available cross-border capacities, resulting in
identical price zones when interconnection
capacities do not limit cross-border trades.
NTC: Net Transfer Capacity, the transfer
capacity made available to the market for
imports and exports, calculated and published
jointly by the system operators. Transfer
capacity depends on the characteristics
and availability of interconnection lines and
internal constraints on the individual countries’
power grids.
Power line circuit length: Actual length of
one of the conductors that form a power line
or the average length of the conductors if they
differ substantially.
PTS: Public Transmission System, over which
electrical energy is carried and transformed,
linking generation sites to consumption sites.
It includes the primary transmission and
interconnection grid (400 kV and 225 kV) as
well as the regional distribution networks (225
kV, 90 kV and 63 kV). This very high voltage
and high voltage grid provides electricity
to heavy industry and the main distribution
system operators.
Reference temperatures: Averages of
past temperature series considered to be
representative of the current decade. Based
on Météo France data, the temperatures are
calculated by RTE for France as a whole thanks
to 32 weather stations throughout the country.
Residential and professional customers:
Final customers to which distribution system
operators provide low-voltage power, with
contracted power of 36 kVA or less.
Seasonally-adjusted data sets: Chronological
series from which the seasonal component has
been removed. Changes in statistical series
can usually be characterised as reflections
of trends, seasonal components, or irregular
components. Adjusting for seasonal variations
is a technique used by statisticians to eliminate
the effects of seasonal fluctuations on data,
thereby revealing fundamental trends.
SER: “Syndicat des Énergies Renouvelables”,
France’s renewable energy association.
SMI/SMEs: Final customers to which
distribution system operators provide mediumand low-voltage power, with contracted power
of 36 kVA or more.
Spot price: Average electricity price
negotiated for delivery the following day in 24
one-hour timeslots.
Water reserves: Filling rate (expressed as a
percentage), corresponding to the relation
between the storage volume recorded
the previous Monday at midnight and the
maximum storage volume, in aggregate.
Outage frequency: Ratio between the number
of outages and the number of distributors and
industrial customer sites supplied by RTE. An
outage is considered to be short if it lasts
between 1 sec and 3 min and long if it lasts
more than 3 min.
Source of data
The information in this publication is based on metering data collected by RTE
on the public transmission network and on data obtained from the distribution
system operators, notably ERDF and EDF Systèmes Énergétiques Insulaires for
Corsica and from ENTSO-E, the European Network of Transmission System
Operators for Electricity. Temperature data are provided by Météo France.
Data as of 31 December 2014
53
Economics, Forecasting and Transparency Division
1, terrasse Bellini TSA 41000
92919 La Défense Cedex
www.rte-france.com
Design & production: PARIMAGE - International communications consulting: BCL Communications - Photo credits: RTE, Météo France (maps p.8), Graphic Obsession (photo p.25)
RTE Réseau de Transport d’Electricité, a limited liability company with Executive and Supervisory Boards, share capital of € 2,132,285,690 Nanterre Register of Commercial and Companies 444 619 258

Annual Electricity Report

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