contents...rte – electricity report 2018 9 a year of contrasts 2018 was one of the warmest years...

RTE – Electricity report 2018 2

Contents SUMMARY ..................................................................................................................................................... 4

GENERATION .......................................................................................................................................................... 4 CONSUMPTION ....................................................................................................................................................... 4 CROSS-BORDER EXCHANGES....................................................................................................................................... 4 NETWORK .............................................................................................................................................................. 5

CONSUMPTION ............................................................................................................................................ 6

TREND IN CONSUMPTION .......................................................................................................................................... 6 BREAKDOWN OF CONSUMPTION BY SECTOR ................................................................................................................ 10 SENSITIVITY TO TEMPERATURES AND END-USES ............................................................................................................ 18

GENERATION ............................................................................................................................................. 26

TOTAL GENERATION ............................................................................................................................................... 26 THERMAL GENERATION ........................................................................................................................................... 35 HYDROPOWER ...................................................................................................................................................... 39 WIND POWER ....................................................................................................................................................... 43 SOLAR POWER ...................................................................................................................................................... 48 BIOENERGY .......................................................................................................................................................... 52 RENEWABLE ENERGY GENERATION ............................................................................................................................ 54 CO2 EMISSIONS ..................................................................................................................................................... 56

TERRITORIES AND REGIONS ................................................................................................................. 60

CONSUMPTION IN THE FRENCH REGIONS .................................................................................................................... 60 WIND POWER IN THE FRENCH REGIONS ...................................................................................................................... 66 SOLAR POWER IN THE FRENCH REGIONS ..................................................................................................................... 71 HYDROPOWER AND BIOENERGY ................................................................................................................................ 74 THERMAL POWER .................................................................................................................................................. 78 THE GENERATION/CONSUMPTION BALANCE ................................................................................................................ 82

EUROPE ....................................................................................................................................................... 86

ELECTRICITY IN EUROPE .......................................................................................................................................... 86 DEMAND COVERAGE RATES IN EUROPE ...................................................................................................................... 91

MARKETS .................................................................................................................................................... 99

MARKET PRICES IN EUROPE ..................................................................................................................................... 99 NET COMMERCIAL EXCHANGES ............................................................................................................................... 107 CWE REGION ..................................................................................................................................................... 111 SPAIN ................................................................................................................................................................ 113 ITALY ................................................................................................................................................................. 117 SWITZERLAND ..................................................................................................................................................... 119 GREAT BRITAIN ................................................................................................................................................... 121 EVOLUTION OF CROSS-BORDER EXCHANGE MECHANISMS ............................................................................................. 122

FLEXIBILITY .............................................................................................................................................. 123

ACTIVITIES OF THE BALANCE RESPONSIBLE PARTIES ..................................................................................................... 123 BALANCING MECHANISM ....................................................................................................................................... 127 DEMAND RESPONSE ............................................................................................................................................. 131 CAPACITY MECHANISM ......................................................................................................................................... 139

THE TRANSMISSION NETWORK .......................................................................................................... 144


HOW THE NETWORK EVOLVED IN 2018 ................................................................................................................... 144 NEW AND REPLACED LINES .................................................................................................................................... 148 2018 HIGHLIGHTS ............................................................................................................................................... 154 MAP OF MAIN PROJECTS COMPLETED ...................................................................................................................... 156 RTE INVESTMENTS ............................................................................................................................................... 158 MAP OF MAIN PROJECTS UNDER WAY ...................................................................................................................... 161 ELECTRICITY QUALITY ............................................................................................................................................ 167 LOSS RATE .......................................................................................................................................................... 171


Summary

Generation

Installed capacity rose by 2 GW during the year, to 132,889 MW. The bulk of this increase was driven by the wind and solar segments (+2.4 GW). Fossil-fired thermal capacity declined following the closure of the last oil-fired plant at Cordemais.

Electricity production was 3.7% higher in 2018 than in 2017, ending the year at 548.6 TWh. Renewable generation (hydropower, solar and wind) was boosted by particularly favourable conditions and represented 22.7% of total production, up from 18.5% in 2017. A gradual rebound in nuclear generation (+3.7%) and a surge in hydropower generation resulted in a decline in production at fossil-fired thermal plants (-26.8%), which in turn drove a 28% decrease in CO2 emissions.

Consumption

Total power consumption has been stabilising for many years thanks to generally improved demand-side management, even as use of electric appliances has grown. Consumption nonetheless contracted slightly year-on-year in 2018, due to temporary factors such as generally warmer weather, especially in the very early and late months of the year, as well as less robust economic growth than in 2017 and significant social movements in the rail transport sector in the spring.

Excluding the energy sector from the calculation, consumption adjusted for weather and calendar effects ended 2018 at 474 TWh, broadly in line with levels seen in 2017 (-0.3%) and the average for the past ten years.

Cross-border exchanges

The exchange balance reached 60.2 TWh in 2018, up sharply from the two previous years. This balance is directly linked to price differences calculated daily between France and its neighbours. Increased availability of the nuclear power plants in France, together with abundant hydropower generation and the numerous instances of unavailability of Belgian nuclear plants late in the year, were among the reasons why price growth was more moderate in France than in neighbouring countries, and thus why exports were resilient.

Exchanges were nonetheless quite volatile throughout the year, ranging from a net import balance of 10 GW on 28 February at 8:00 am to a net export balance of 16.2 GW on 22 January at 3:00 am. France was a net importer on 17 days in 2018 (vs. 52 days in 2017).


Network With 105,857 km of lines in service, the transmission network continues to guarantee security of supply to the territories and regions while boosting the system’s ability to accommodate renewable energy sources. RTE’s total investments within the scope of activities regulated by the CRE totalled €1,447 million in 2018. Investments primarily focused on completing the upgrading of the 225 kV line between Cergy and Persan to 400 kV, securing supply to the Préguillac area (225 kV lines for Préguillac-Saintes and Farradières-Saintes), continuing work on the new interconnection with England (“IFA2”) and the DC interconnection between France and Italy (“Savoy-Piedmont”), and restructuring the 225 kV network in Haute-Durance.


Consumption

Trend in consumption

Demand has been stabilising

For several years now, the long-term trend has been toward a stabilisation of total electricity demand, thanks to generally improved demand-side management and despite increased use of electric appliances.

Consumption nonetheless declined slightly year-on-year in 2018, due to temporary factors including generally warmer weather, especially in the very early and late months of the year, as well as less robust economic growth than in 2017 and significant social movements in the rail transport sector in the spring.

Gross consumption

Gross consumption ended the year at close to 478 TWh, down 0.8% from 2017.

Trend in gross consumption


Why are adjustments made to gross consumption?

To better identify structural trends

When it is very cold outside, electricity is used for heating. When the weather is very hot, people use power for cooling. To better analyse structural trends from one year to the next, power consumption data is adjusted to strip out “weather effects”. Once this is done, electricity demand corresponds to what would have been consumed if temperatures had been the same as reference temperatures.

Adjustments can be made for other factors as well. For instance, February has an extra day in leap years. To strip out this calendar effect, consumption is adjusted in such a way as to count only 365 days.

For a better understanding


éCO2mix: Everything you want to know about electricity in France and your region or city

Eco2mix is an educational tool designed to promote transparency.

Whether you are an ordinary citizen trying to better understand electricity

to become a more responsible consumer, a knowledgeable amateur or an

energy professional, you can use éCO2mix in a fun or expert manner to

monitor power system data at the national, regional and city levels. It can

also be used to understand your power consumption and get advice on how

to reduce it and take simple actions to prevent or reduce the risk of a

system imbalance if a power warning is issued.

http://www.rte-france.com/eco2mix

Adjusted consumption

To get a clearer picture of structural trends, RTE makes adjustments to account for the impact on demand of weather and the extra day in February in leap years. Adjusted consumption thus reflects what demand would have been at reference temperatures and for a year with 365 days.

Excluding the energy sector from the calculation, consumption adjusted for weather and calendar effects ended 2018 at 474 TWh, broadly in line with the total for 2017 (-0.3%) and the average for the past ten years.

Consumption adjusted for weather

Note: To calculate adjusted consumption, it is necessary to exclude the energy sector because the adoption of a new uranium enrichment process in 2012 severely impacted the sector and caused a steep decline in consumption.

Closer look


A year of contrasts

2018 was one of the warmest years on record (average temperature +0.7°C relative to the reference), with temperatures even exceeding the 2014 level.

An analysis of daily statistics (source: Météo France) nonetheless reveals some contrasting trends:

Temperatures were exceptionally mild in the early months of the year, with January 2018 ranking as the warmest January on record since 1900;

Conversely, average temperatures were 2.2°C below normal in February 2018, as that month ended with a relatively late cold snap;

After a gloomy spring, July and August were, respectively, the third and fourth hottest months of July/August on record since 1900. The summer of 2018 was thus the second hottest summer (though not nearly as hot as 2003).

Adjustments are made for these changes in consumption analyses in order to better identify underlying trends.

Temperature trends in France relative to reference temperatures


Breakdown of consumption by sector

Little change in breakdown by sector

The breakdown of consumption by sector was comparable to 2017. It should be noted that the slight decrease in consumption in heavy industry followed significant social movements in the rail transport sector and an incident at the site of an industrial customer in the metallurgy sector.

The residential segment was once again the largest consumer of electricity,

accounting for about 35.7% of final consumption, followed by the business sector

(26.6%), heavy industry (16.9%), SMEs/SMI (11%) and professionals (9.9%).


Who are RTE’s customers? RTE works on behalf of society and its own customers – producers and distributors of electricity, industrial firms and traders – to offer solutions that help keep power system costs in check and thus preserve economic activity.

As the transmission system operator, RTE plays a central role in the power system and

is responsible for ensuring that generation always matches demand. It works around the

clock, seven days a week, to direct electricity flows and optimise the functioning of the

power system for its customers and society at large. RTE carries electricity to all parts of

France, from generation sites to the industrial sites that are directly connected to its

network and to the distribution grids that deliver it to final consumers.

Find out more about our customers here



Consumption was stable on the distribution networks and among SMEs/SMI, professionals, businesses and residential users

Electricity consumption, including the losses of distribution networks and adjusted for seasonal factors, was stable among SMEs/SMI, professionals, businesses and residential users connected to the distribution grids.

Consumption by SMEs/SMI, professionals, businesses and residential customers Seasonally adjusted

The application of directives and regulations on the energy efficiency of equipment contributed to this trend. Another factor was slower growth in the share of new buildings heated with electricity, due to the application of the 2012 Building Energy Regulation.


Demand contracted slightly in heavy industry

Electricity consumption by industrial users* directly connected to the public transmission network reached 66.2 TWh, which was 1.8% lower than in 2017. This year-on-year decrease was driven primarily by significant social movements in the rail transport sector in the spring and an incident at the site of an industrial customer in the metallurgy sector.

Consumption by heavy industry, excluding the energy sector Seasonally adjusted

* including own consumption but excluding losses and the energy sector


Consumption down slightly in most segments of industry

Consumption trends varied from one segment of industry to the next in 2018.

With the exception of car manufacturing and light industry, which saw year-on-year increases of 0.1% and 3.4%, respectively, all segments of industry recorded slight declines. The steepest decrease was seen in metallurgy (-7.6%), after an incident occurred at the site of an industrial customer. Next were rail transport (-6%, due mainly to social movements), paperboard (-3.1%), chemicals (-2.1%), steel (-1.7%) and energy (-0.9%).


Greater energy efficiency in heavy industry

Power consumption in heavy industry is closely correlated to industrial output. However, improved processes, and in some cases changes in means of production, have made energy use more efficient. Shown here is a graphic analysis of industrial output and power demand curves. Consumption and output levels move closer to one another – this is notably visible in the chemicals, car manufacturing and paperboard segments – which can be explained by increased energy efficiency, assuming no transfers in end-uses.


* Base 2015: Average industrial production index (INSEE) for the reference year 2015 is equal to 100


Sensitivity to temperatures and end-uses

Peak demand sets another record

Electricity consumption peaked for the year at 96.6 GW on Wednesday, 28 February 2018 at 7:00 pm, as a late cold spell moved into France. This was the third highest peak ever recorded in France.

Historical trend in peak demand

Demand reached its lowest point for the year on Sunday 12 August, when it fell to 30.4 GW.


Trends in maximum and minimum demand


What drives peaks and valleys in demand?

Consumption in France varies greatly depending on the season, the day of the week and the time of day.

Electric heating causes demand to reach higher levels in winter than in summer.

Similarly, people are more active during the week than on weekends, so demand is higher on weekdays.

Over the course of a day, the use of lighting and cooking for example, particularly in the evening, when people tend to return home, explains the spike observed at around 7:00 pm.



In winter, demand increases by 2,400 MW with each degree Celsius drop in temperatures

Power demand in France is very sensitive to temperatures, particularly in the winter

months, due to the widespread use of electric heating.

RTE uses a model that distinguishes between temperature-sensitive and non-temperature-sensitive demand to calculate weather-adjusted consumption. It is the temperature-sensitive share that determines the shape of the overall demand curve.

Gross consumption and temperature-sensitive share in winter 2017-2018

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.


Energy efficiency: Households are consuming less energy

Household appliances are increasingly efficient, and this efficiency is helping households save on their energy bills.

It was estimated in 2016 that households consumed an average 2,350 kWh a year for domestic electricity uses. This consumption would be halved if households were equipped exclusively with efficient appliances (A+++).


See the Generation Adequacy Report

Detailed consumption forecasts and trends linked to end-uses can be found in the 2017 Generation Adequacy Report (additional link: 2018 Generation Adequacy Report)

Demand by end-use

Hourly loads* on the two charts below show substantial seasonal variability. This is due in large part to the use of heating in winter.

Demand by end-use in winter

Weekly profile of power demand at reference temperatures by end-use during a typical week in January

Demand by end-use in summer

Weekly profile of power demand at reference temperatures by end-use during a typical week in June

* Note that these charts show power demand at reference temperatures. Actual demand is much more variable. For more information, return to the section on temperature sensitivity by clicking on “Return to content” at the bottom of this page.

Closer look


Demand by sector

Analysis of the breakdown of demand by sector over one year reveals:

Significant reliance on electric heating in winter, reflected in power demand in the residential sector and, to a lesser degree, in the tertiary sector;

A brief dip in demand in the tertiary sector and industry late in December, when economic activity slows due to the year-end holidays. Decreases are also seen in both sectors during the school holidays (in August, for example).


Demand by end-use over the year

Average weekly demand at reference temperatures by end-use for a typical July- June period

Demand in the residential sector Average weekly demand at reference temperatures for a typical July-June period

Demand in the tertiary, agricultural and transport sectors Average weekly demand at reference temperatures for a typical July-June period

Demand in the industrial sector Average weekly demand at reference temperatures for a typical July-June period


Generation

Total generation

Installed capacity +2 GW

Generation capacity in mainland France ended the year at close to 133 GW (132.9 GW to be precise), up 2 GW (+1.6%) from 2017. Wind and solar power accounted for the lion’s share of this increase. Fossil-fired thermal capacity was down sharply because of the closure of the last oil-fired plant at Cordemais.

Installed capacity at 31/12/2018

Capacity in MW Change relative

to 31/12/2017 Change in MW

Share of total capacity

Nuclear 63,130 0% 0 47.5%

Fossil-fired thermal

18,588 -2.3% -439 14%

of which coal 2,997 0% 0 2.3%

of which oil 3,440 -16.1% -657 2.6%

of which gas 12,151 +1.8% 218 9.2%

Hydropower 25,510 -0.04% -11 19.2%

Wind 15,108 +11.2% 1,558 11.5%

Solar 8,527 +11.4% 873 6.4%



Capacity in MW Change relative

to 31/12/2017 Change in MW

Share of total capacity

Bioenergy 2,026 +4.2% 73 1.5%

of which biogas 452 4.6% 20 0.3%

of which biomass

634 6.4% 38 0.5%

of which paper waste

57 0% 0 0.04%

of which

municipal waste

883 1.8% 15 0.7%

Total 132,889 +1.6% 2,054 100%

Installed capacity in France as of 31/12/2018


View the national registry of power generation and storage facilities

Since 2017, RTE has been listing the main characteristics of French power generation and storage facilities on OpenData Réseaux Energie, which is updated every month. Information provided includes the location of facilities, the technology and fuel used, capacity, annual output, etc. The data comes from all system operators in mainland France and the overseas territories. Click here.

Energy and power

Understanding the difference between energy and power

Power (measured in watts, symbol W) represents a generation resource’s ability to deliver a quantity of energy per unit of time. A watt-hour (Wh) quantifies the energy delivered: 1 Wh is the energy produced by a 1 W generation facility over a one-hour period (1W × 1h). In addition to kilowatt-hours (kWh = 103 Wh), larger multiples of watt-hours are often used to describe electricity generation: megawatt-hours (MWh = 106 Wh), gigawatt-hours (GWh = 109 Wh) and terawatt-hours (TWh = 1012 Wh). The energy consumed in one hour corresponds to power delivered to meet demand during that hour.



Electricity generation up sharply

Total power generation in France reached 548.6 TWh in 2018, up 3.7% from 2017. This was the biggest year-on-year increase since 2010. Renewable energy sources accounted for close to 20% (versus 16% in 2017) of total electricity production. The largest increase was in the hydropower segment (+27.5%). Wind and solar power also made substantial contributions with increases of 15.3% and 11.3%, respectively. Nuclear power generation was up 3.7% year-on-year but, like in 2017, its share of total electricity generation was near the lowest level since 1992. Logically, rising overall power production led to a sharp reduction in fossil-fired thermal generation: the latter ended the year down by 26.8% whereas renewable generation was up 21.9%.

Energy produced TWh Change

2018/2017 Share of

generation

Net generation 548.6 +3.7% 100%

Nuclear 393.2 +3.7% 71.7%

Fossil-fired thermal 39.4 -26.8% 7.2%

of which coal 5.8 -40.3% 1.1%

of which oil 2.2 -26.6% 0.4%

of which gas 31.4 -23.6% 5.7%

Hydropower 68.3 +27.5% 12.5%

of which renewable 63.1 +30% 11.5%

Wind 27.8 +15.3% 5.1%

Solar 10.2 +11.3% 1.9%

Bioenergy 9.7 +2.3% 1.8%

of which biogas 2.4 +7.3% 0.4%

of which biomass 2.8 +4.8% 0.5%


The future of the energy mix

Wind power, tidal and wave energy… marine energy sources hold real potential. Their integration into the power system will contribute to a successful energy transition and the development of a new industry. MAG RTE&Vous describes how RTE and its partners are meeting the challenges involved in connecting these new power sources to the grid.


2018/2017 Share of

generation

of which paper waste 0.3 -10.1% 0.1%

of which non-renewable municipal waste

2.1 -0.9% 0.4%

of which renewable municipal waste

2.1 -0.9% 0.4%

Closer look


Fossil-fired thermal capacity by technology


Power MW

Change relative to 31/12/2017

Change in MW

Share of capacity

Coal 2,997 0% 0 2.3%

Oil 3,440 -16.1% -657 3%

Combustion turbines 1,403 0% 0 1.1%

Co-generation 457 0% 0 0.3%

Other* 1,580 -29.4% -657 1.2%

Gas 12,151 1.8% 218 9.2%

Combustion turbines 703 0% 0 0.5%

Combined-cycle gas 6,258 0% 0 4.7%

Co-generation 4,883 3.9% 183 3.5%

Other* 306 +13.2% 35 0.2%

Total 18,588 -2.3% -439 14%

* Sources other than combustion turbines, co-generation and combined-cycle gas plants


Fossil-fired thermal generation by technology


2018/2017 Share of

generation

Net fossil-fired thermal generation

39.4 -26.8% 7.2%

Coal 5.8 -40.3% 1.1%

Oil 2.2 -26.6% 0.4%

Combustion turbines 0.3 -8.2% 0.1%

Co-generation 0.6 -18.1% 0.1%

Other* 1.3 -33% 0.2%

Gas 31.4 -23.6% 5.7%

Combustion turbines 0.1 -73.5% 0.02%

Combined-cycle gas 17.4 -33.3% 3.2%

Co-generation 11.6 -16.8% 2.1%

Other* 2.2 +307.1% 0.4%



Variability of generation from different sources

France’s generation mix comprises resources that are sensitive to various parameters: cloud cover and sunlight for solar power, wind conditions for wind power, rainfall and temperatures for hydropower. For example, coverage of demand with hydropower is at its highest (as much as 32%) in May, when snow is melting. This generation can also be modulated and, to a degree, used to help offset fluctuations in wind and solar power output.

Facilities that run on fossil fuels (coal, oil and gas) are typically powered up more often in the winter. Their coverage of total demand ranged between 1% and 17% in 2018.


The extremities represent the maximum and minimum and the white line the median.


Thermal generation

Nuclear: Production up slightly

Installed nuclear capacity ended the year unchanged at 63.1 GW, which represents about half of total French capacity (133 GW). As plant availability was higher than in 2017, nuclear generation rose (+3.7%, +14.06 TWh) and accounted for 71.4% of total power production in France.

Nuclear generation


Did you know?

CO2 is a parameter factored into the variable production costs of fossil-fired plants. In 2018, a sharp increase in the price of CO2 allowances notably favoured gas-fired plants over coal-fired ones, as they emit less CO2 per MWh produced.

Fossil-fired thermal generation impacted by closure of last oil-fired plant

Fossil-fired thermal plants were powered up less often in 2018 due to a gradual rebound in nuclear generation together with a surge in hydropower generation. Total production in this segment declined sharply relative to the exceptionally high figure for 2017 (-26.8%). The last oil-fired plant at Cordemais was taken out of service on 31 March 2018 and officially closed on 31 December 2018. Commissioned in 1976, the plant had a capacity of 700 MW. It was the last large oil-fired plant connected to the transmission grid in France.

Fossil-fired thermal generation



Rising renewable electricity generation reduced reliance on fossil-fired peak plants

Monthly output from fossil-fired and renewable energy sources in 2018 (excluding hydropower)

Renewable generation increased between 2017 and 2018. One consequence was that fossil fuel plants were fired up less often.

In the first quarter of the year, fossil-fired thermal plants were relied upon heavily to cover peak demand during winter cold spells. Wind power generation was also strong in the first quarter as the winter months were windy. Temperatures were milder than usual in January, as a result of which production decreased across all technologies.

In the third quarter, different factors came together to tighten the supply-demand balance. One was a decrease in wind power output relative to the first part of the year. At the same time, an exceptionally hot month of July drove energy demand up sharply, notably due to the use of air conditioning. Lastly, nuclear generation declined in August, as environmental regulations prevent plants from discharging water hot enough to potentially disturb the ecological balance.

These factors combined to drive up electricity production at fossil-fired thermal plants relative to the previous quarter. It should also be noted that solar radiation was strong in the latter part of the second quarter and the third quarter, resulting in particularly high solar power generation.

Production started trending upward again in the fourth quarter, as energy demand naturally increases in winter.


Map of fossil-fired plants in France


Hydropower

Sharp increase in hydropower generation

Hydropower generation surged by 27.5% year-on-year in 2018, to the second highest level on record since 2007. This jump in production is explained by surplus rainfall that climbed as high as 40% in the first five months of the year.

Hydropower generation


Increase in water reserves

Water reserves were higher than in 2017 throughout the year, except between weeks 9 and 18. Reserves ended the year up by 12.6%. They were even 45% higher than in 2017 early in the year (weeks 4 to 6) and toward the end (weeks 49 to 52).

Weekly water reserves in 2017 and 2018


Hydropower generation by type of plant

Pondage

The reservoirs of pondage facilities, usually located in lakes below midsized mountains, can be filled in 2 to 400 hours. They are used for daily, and even weekly modulation (daily peaks in demand, between business and nonworking days, etc.).

Monthly output from pondage facilities

Run-of-river

Run-of-river plants are primarily located on plains and have small reservoirs that can be filled in less than two hours. They thus have little capacity for modulation through storage, and their production depends on water flows.

Monthly output from run-of-river plants


Reservoir

Reservoir plants are built at the foot of midsized and tall mountains and have a filling period of more than 400 hours. They are used for seasonal storage.

Monthly output from reservoir plants

Other

“Other” hydropower plants are tidal and pumped storage plants (Station de Transfert d’Energie par Pompage – STEP). Tidal power plants harness energy from tides in coastal

areas with strong tidal currents (difference in water levels between successive high and low tides). These plants harness tidal ranges to produce electricity, making use of the difference in heights between two basins separated by a dam.

STEP plants operate in pumping-turbining cycles between a lower and an upper reservoir, using reversible pump-turbines. They are an efficient storage tool and help ensure the balance of the power system. If the reservoirs have natural inflows, the turbines fall into the “mixed pumped storage” category. Otherwise they are considered “pure storage”.

Monthly output from other hydro plants


Wind power

Installed capacity rose to 15.1 GW: Multiannual Energy Programme targets for 2018 met

As of 31 December 2018, installed wind power capacity in France stood at 15,108 MW, after 1,558 MW of new capacity was connected to the grid. Of this total, 1,024 MW was connected to the RTE network and 14,084 MW to the grids of Enedis, LDCs and EDF-SEI for Corsica. Installed capacity rose 11.2% over the year, and the 15,000 MW target set out for 2018 in the Multiannual Energy Programme was exceeded.

Installed wind capacity


Wind power output up for the year

Wind power production was 15.3% higher than in 2017. It was boosted by an increase in installed capacity and also by particularly favourable weather conditions.

Wind power generation


Multiannual Energy Programme targets

The targets set forth in the Multiannual Energy Programme (in terms of generation capacity) are split between technologies as follows:

Technology Targets for 2018 Targets for 2023 (MW*)

Wind 15,000 27,000 (of which 2,400 offshore)

Solar 10,200 20,600

* The targets for 2023 are still in the public debate phase


Wind power output at half-hourly intervals

On average, the first and last deciles increased (by 10.2% and 13.4%, respectively). This upward trend reflected the favourable weather conditions observed over the year. Given that there are several wind regimes in France, the wide spread of geographic sites tends to compensate for the variability of wind power generation resulting from changes in wind conditions.

Wind power output at half-hourly intervals (average and first/last deciles)

Demand covered by wind power

On average, wind power covered 5.8% of demand in 2018, compared with 5% in 2017.

Demand covered by wind power


Monthly wind power generation

Wind power production peaked for the year on 9 December, at 1:30 pm, with generation reaching 12,124 MW. This was achieved by mobilising 80.3% of France’s total installed wind power capacity.

Monthly wind power generation

Monthly wind capacity factor

The monthly wind power capacity factor averaged 21.1%, which was slightly higher than in 2017 (20.3%).

Monthly wind capacity factor


Solar power

Increase in installed solar capacity

Installed solar capacity in France ended 2018 at 8,527 MW. Of this, 7,886 MW was connected to the grids of Enedis, LDCs and EDF-SEI for Corsica, and 641 MW to the transmission network. The increase in capacity relative to 2017 was 11.4%. Capacity additions were within the average for the past five years, with 873 MW connected. Additions represented 84% of the targets set forth in the Multiannual Energy Programme for 2018 (10,200 MW).

Installed solar capacity


Output rose in line with installed capacity

Solar power output rose by 11.3% year-on-year in 2018, reflecting the increase in installed capacity as well as favourable weather conditions.

Solar power generation

Multiannual Energy Programme targets

The targets set forth in the Multiannual Energy Programme (in terms of generation capacity) are split between technologies as follows:

Technology Targets for 2018 Targets for 2023 (MW*)

Wind 15,000 27,000 (of which 2,400 offshore)

Solar 10,200 20,600

* The targets for 2023 are still in the public debate phase


Monthly solar capacity factor

The average solar capacity factor decreased slightly year-on-year in 2018, from 14.7% to 14%. Use of installed solar capacity did not exceed 75% during the year.

Monthly solar capacity factor

Solar power output at half-hourly intervals

Solar power covered an average 2.1% of demand in 2018, up from 1.9% in 2017. The last decile increased by 16.2% year-on-year, reflecting the availability of newly installed capacity during the year as well as good solar radiation.

Solar power generation at half-hourly intervals (average and first/last deciles)


Monthly solar power output

On 23 June 2018, at 2:00 pm, solar power generation reached a record high of 6,290 MW, with a capacity factor of 75.1%. Solar plants operate at their maximum power in the summer months (June, July, August).

Monthly solar power generation


Bioenergy

Moderate increase in installed capacity

Installed bioenergy capacity rose above the symbolic 2 GW mark in 2018 (+3.8% vs. 2017). Capacity additions slowed relative to the 2012-2016 period for the second year in a row.

Installed bioenergy capacity


Breakdown of bioenergy capacity

Municipal waste incineration plants still account for the lion’s share of bioenergy capacity.


Renewable energy generation

Renewable coverage of demand hit an all-time high

Renewable coverage of power demand rose from 18.5% in 2017 to 22.7% in 2018. This record high is a direct consequence of the excellent production figures achieved in the different segments, thanks to weather conditions that were conducive to operating renewable energy facilities and to a further increase in installed capacity.

Hydropower accounted for 58.1% of coverage, wind power for 25.6%, solar power for 9.4%, and bioenergy for 6.9%.

Share of annual electricity production from renewable energy sources as a percentage of total demand


Method of calculating renewable generation

The calculation method used is drawn from EU Directive 2009/28/EC. Seventy percent of consumption for pumping is deducted from production at pumped storage stations. Municipal waste incineration plant output is counted at 50%. The methodology used here does not make adjustments for weather conditions.


CO2 emissions

CO2 emissions down sharply during the year

CO2 emissions decreased by 28% in 2018, falling back toward the 2015 level. Increases in nuclear and hydropower generation reduced reliance on fossil-fired thermal plants during the year. Total CO2 emissions resulting from own consumption were estimated at 3.47 million tonnes (-5.2% relative to 2017). These emissions are included in the carbon footprint assessments of the industrial sites in question.

CO2 emissions excluding own consumption (millions of tonnes) from January to December

2018 2017

Net production 20.4 28.3

Nuclear – –

Fossil-fired thermal 18.7 26.6

of which coal 5.6 9.5

of which oil 1.1 1.5

of which gas 12 15.6

Hydropower – –

Wind power – –

Solar power – –

Municipal waste (incineration) 1.7 1.7


Trend in CO2 emissions since 2008

Calculating CO2 emissions

The CO2 emission factors shown here only represent CO2 emissions generated by consumption of the primary fuel source. Different generation technologies contributed to CO2 emissions as follows:

- 0.986 t/MWh for coal-fired units - 0.777 t/MWh for oil-fired units - 0.486 t/MWh for newer gas combustion turbines - 0.352 t/MWh for combined-cycle gas turbines - 0.583 t/MWh for older gas combustion turbines and other gas-fired plants - 0.988 t/MWh for municipal waste incineration (only the non-renewable share, or

50% of generation, counts towards emissions).

These rates are calculated based on emission factors published by ADEME and plant efficiencies based on ENTSO-E recommendations.


CO2 emissions from fossil-fired thermal plants by technology

CO2 emissions excluding own consumption (millions of tonnes)

2018 2017

Coal 5.6 9.5

Oil 1.1 1.4

Combustion turbines 0.1 0.1

Co-generation 0 0

Other* 1 1.5

Gas 12 15.6

Combustion turbines 0 0.2

Combined-cycle gas 5.5 8.4

Co-generation 5.5 7

Other* 1 0

Total 18.7 26.6



CO2 emissions vary over time

CO2 emission were higher than in 2017 during the rare periods when the use of fossil-fired thermal plants was equal to or greater than the previous year.

Monthly CO2 emissions excluding own consumption


Regional electricity data with éco2mix

Use the éco2mix app to get real-time information about electricity in each region.

City-specific versions of éco2mix also provide real-time data.

Territories and Regions

Consumption in the French regions

Gross consumption was flat on average

Gross consumption in the French regions declined relative to 2017 in all regions except Brittany and Occitanie, which saw increases of 1.1% and 0,6%, respectively. The steepest decline was recorded in Bourgogne Franche-Comté (-2.5%).

Closer look


Adjusted consumption: Trends shaped in part by demographics

Between 2007 and 2017, trends in adjusted consumption in France were mixed due to a variety of factors, one of which was demographics. This was the case in Occitanie, where electricity consumption rose by almost 8% as the population grew by more than 9%.

The Grand-Est saw the steepest decrease in adjusted consumption in France (-9%) due to the region’s deindustrialisation.

Trend in adjusted consumption between 2007 and 2017


Population growth between 2007 and 2017


Consumption in heavy industry declined

The Hauts-de-France and Auvergne-Rhône-Alpes regions are home to the largest number of industrial sites connected to the transmission grid. Consumption declined relative to 2017 in all regions except Brittany (+7%) and Auvergne-Rhône-Alpes (+2%). Nouvelle-Aquitaine recorded a decrease of more than 7%.

Consumption in heavy industry, excluding the energy sector, in 2018


Key heavy industry areas

Heavy industry


Breakdown of heavy industry consumption by sector in the French regions


Wind power in the French regions

Installed capacity

Climate conditions (wind regimes), environmental constraints and local political priorities explain the differences between wind power development rates. The two regions that have the most wind capacity installed are Hauts-de-France (4 GW) and Grand-Est (3.37 GW). Capacity was increased by more than 10% in six regions between 2017 and 2018.

Regional map of wind capacity


Regional wind power targets

The map below shows the wind power targets set forth in France’s regional climate-air-energy plans, aggregated according to the new administrative regions and taking into account region-specific climate, environmental and policy considerations.

Regional wind power targets for 2020

By 2019, the regional climate-air-energy plans will be integrated into the regional plans for land use, sustainable development and territorial equality (schémas régionaux d’aménagement, de développement durable et d’égalité des territoires - SRADDET) created by Law 2015-991, known as the NOTRe Act.


Wind power generation

Coverage of demand by wind power reached 5.8% in the French regions and exceeded 10% in the Hauts-de-France, Grand-Est and Centre-Val de Loire regions.

Coverage of demand by wind power


Wind regimes

Wind energy has developed in the different regions thanks, among other factors, to favourable local climate conditions that guarantee certain wind speeds and thus a higher average capacity factor. Wind zones in mainland France can be divided into four homogeneous areas. Windy periods within a defined wind zone tend to occur at the same time and be of similar intensity. Significant differences are observed between patterns in the four zones. It is this diversity across the country that makes it possible to have wind turbines operating virtually all the time in France.

Four homogeneous wind zones


Regional density of wind capacity

Density is a calculation of wind capacity per square kilometre in each region. The Hauts-de-France region has the most installed capacity and the highest density. Occitanie ranks third in terms of capacity but seventh in terms of density, below the national average of 27.4 kW per square kilometre.


Solar power in the French regions

Installed capacity

Three regions have more than 1.2 GW of installed solar capacity: Nouvelle-Aquitaine, Occitanie and Provence-Alpes-Côte d’Azur. These regions account for more than 62% of installed solar capacity in France, due to their geographic location in the southernmost part of the country, where conditions are favourable for solar power use and development. The Auvergne-Rhône-Alpes region saw the sharpest increase in installed solar capacity during the year (more than 19%).

Regional map of solar capacity


Regional solar power targets

Regional solar power development targets for 2020 focus primarily on southern France.

Regional solar power targets for 2020


Solar power generation

Coverage of demand in the French regions by solar power exceeded 5% in Corsica and the Occitanie and Nouvelle-Aquitaine regions.

Coverage of demand by solar power


Hydropower and bioenergy

Installed bioenergy capacity

Bioenergy plants are found throughout France. The Ile-de-France, Nouvelle-Aquitaine and Provence-Alpes-Côte d’Azur regions are each home to more than 14% of the country’s total bioenergy capacity.

Regional map of bioenergy capacity


Bioenergy generation

Coverage of demand in the French regions by bioenergy is highest in Nouvelle-Aquitaine, where it exceeds 3%.

Coverage of demand by bioenergy


Hydropower

France’s 25.5 GW of installed hydropower capacity is divided unevenly across the country.

Regions with large mountainous areas (Auvergne-Rhône-Alpes, Occitanie and Provence-Alpes-Côte d’Azur) are home to more than 79% of total French hydropower capacity. Most of the facilities are hydroelectric dams, notably water reservoir and pondage facilities. Hydropower capacity in other regions is smaller and often relies on run-of-river or pondage systems.

Regional map of hydropower capacity


Hydropower generation

Coverage of demand by hydropower was highest in the Auvergne-Rhône-Alpes region, where it exceeded 40%.

Coverage of demand by hydropower


Thermal power

Fossil-fired thermal capacity

Fossil-fired thermal plants can be found throughout the French regions. Most capacity is in the Hauts-de-France, Pays de la Loire, Grand-Est and Provence-Alpes-Côte d’Azur regions, which together are home to around 60% of total fossil-fired thermal capacity. Because they require water for system cooling, these plants are located near water points (e.g. Cordemais on the Loire River).

Regional map of thermal capacity


Fossil-fired thermal generation

Fossil-fired thermal generation covers more than 15% of demand in Corsica and the Grand-Est, Haut-de-France and Pays de la Loire regions.

Coverage of demand by fossil-fired thermal power


Nuclear power capacity

Most of the nuclear reactors in France are in the Normandy, Grand-Est, Centre-Val de Loire and Auvergne-Rhône-Alpes regions, which are together home to 77% of the plants in service. Because of their cooling requirements, the plants are located near water points: along the coast (e.g. Paluel and Flamanville, on the English Channel) or waterways (e.g. Tricastin and Cruas on the Rhône).

Nuclear capacity was unchanged in 2018 (63.1 GW).

Regional map of nuclear power capacity


Nuclear power generation

Nuclear power generation covers demand in the Centre-Val de Loire region nearly four times.

Coverage of demand by nuclear power


The generation/consumption balance

The transmission grid is helping to ensure interregional solidarity

Electricity generated in the regions not only meets local needs but also helps cover demand in neighbouring areas. The Centre-Val de Loire and Grand-Est regions produce much more than they consume and thus make a great contribution to this interregional solidarity. The regions that rely heavily on electricity imports, such as Ile-de-France, Bourgogne-Franche-Comté and Brittany, know that they will have enough supply to keep up with demand. Most of these exchanges flow over the public transmission grid.


Power flows between regions


Solidarity between the regions

Interregional exchanges

Consumption during very cold periods

In February of 2018, the average temperature was 2.2°C below normal. This widespread cold spell drove power demand higher due to the large share of electric heating in France.

Trend in gross consumption in the French regions in February and March 2018


Impact of heatwaves on consumption

July and August 2018 were respectively the third and fourth hottest months of July and August on record since 1900. Widespread use of air conditioning is reflected in higher power consumption on particularly hot days.

Trend in gross consumption in the French regions in July and August 2018

Impact of rainfall on hydropower output

Annual fluctuations in hydropower output are closely correlated to precipitation. Hydropower production increased across all regions in 2018, after a significant rainfall deficit depressed output in 2017.

Trend in hydropower output in the regions in July and August 2018


2017-2018 data

The data presented in this chapter comes from ENTSO-E’s Power Statistics platform. It corresponds to the period from July 2017 to June 2018, and comparisons are against the previous 12 months (July 2016 to June 2017).

Europe

Electricity in Europe



Consumption was flat in Europe

Total gross consumption in ENTSO-E countries was unchanged from the previous 12 months, ending the period at 3,331 TWh (-0.1%). Large discrepancies were seen between countries: demand continued to rise in Eastern Europe but stabilised in countries like France and the Netherlands and even declined in Great Britain. Consumption was higher in the Baltic and Nordic countries as the winter was colder than in previous years.

Data calculated for the period from July 2017 to June 2018 vs. the previous 12 months

Annual trend in power consumption


Germany and France were the biggest exporters

Germany once again showed the highest exports for the 2017-2018 period (+52.2 TWh), followed closely by France (+51.7 TWh), where nuclear power plant availability was much higher than in the previous winter. Conversely, Italy remained the biggest importer in Europe (-43.3 TWh), again followed by Finland (-20 TWh) and Great Britain (-18.9 TWh).


Sum of physical flows


Electricity generation was flat

European power generation reached 3,371 TWh in 2017-2018, unchanged from the previous period. Demand was also flat. Production increased sharply in France (+18 TWh) and, to a lesser degree, in Switzerland (+7 TWh) and Sweden (+6 TWh). Five countries together accounted for close to 60% of total production in ENTSO-E countries: Germany (18%), France (16%), Great Britain (9%), Italy (8%) and Spain (8%).


Individual countries’ share of total ENTSO-E generation


France is the most temperature-sensitive country in Europe

A country’s electricity consumption is sensitive to temperatures. Demand increases with colder weather, notably due to the use of electric heating. Known as temperature sensitivity, this phenomenon is observed in all European countries, but it is by far the most pronounced in France.

The chart below helps illustrate the existence of this temperature sensitivity: it traces daily consumption in a given country based on the average temperature in that country. Bank holidays, the year-end holidays and the month of August are not represented since demand is so much lower than normal during these periods.

Below 15°C, consumption begins to increase as the temperature decreases. The curve is three to five times steeper in France than elsewhere. In some countries, temperature sensitivity is observed in summer when the temperature climbs above 20°C. Consumption notably increases with temperatures in Spain, and even more so in Italy, due in part to the use of air conditioning.

Daily consumption based on temperatures (working days, July 2017-June 2018)


Demand coverage rates in Europe

Nearly a quarter of European demand is covered by nuclear

Of the 34 ENTSO-E countries, 15 have electricity mixes that include nuclear. Coverage of demand by nuclear generation was 24% in 2018, broadly unchanged from a year earlier (+0.7%).

Nuclear generation rose in France and, to a lesser extent, in the Czech Republic, due to greater availability of the nuclear fleets in those countries. Conversely, it contracted sharply in Great Britain, Sweden and Spain.



Coverage of demand by nuclear power


Decrease in fossil-fired thermal generation

Fossil-fired thermal generation declined in Europe and covered 39% of demand in ENTSO-E countries in 2017-2018. Generation contracted sharply in several countries, particularly Germany and Great Britain. In France, increases in nuclear and hydropower output made it possible to rely less on fossil-fired plants, such that coverage of demand dipped back below 10%.


Coverage of demand by fossil energy


Hydropower generation up thanks to rainfall

Hydropower generation increased in Europe and covered 17.6% of demand in ENTSO-E countries, up from 15.7% in the previous 12-month period. This increase reflected higher rainfall, particularly in the Alps and Pyrenees. Coverage exceeded 50% in countries geographically situated in such a way as to allow a large number of hydropower plants (Norway, Iceland, Switzerland and Austria).


Coverage of demand by hydropower


11% of European demand covered by wind power

Wind power covered more than 20% of demand in Denmark, Ireland, Portugal and Germany in 2018. The rate even exceeded 40% in Denmark, with a third of production coming from offshore farms. Average coverage in ENTSO-E countries ended the year at 11%, which was higher than in the previous 12-month period.


Coverage of demand by wind power


Increase in solar power generation

Across ENTSO-E countries, solar power covered 3.4% of demand in 2018, up slightly from a year earlier. Germany and Italy accounted for more than 50% of solar power generated in Europe.


Coverage of demand by solar power


Increase in renewable energy generation

Renewable energy generation increased in Europe though output still varied greatly from one country to the next. In Norway, renewable output exceeded domestic consumption, though other types of generation are available if needed to ensure uninterrupted power supply throughout the year. Coverage rates exceeded 40% in Germany and hit 34% in Italy and 35% in Spain.

Average coverage of demand by renewable sources in ENTSO-E countries was 36%, up from the previous period thanks to abundant rainfall and ever increasing wind power generation.


Coverage of demand by renewable sources


Markets

Market prices in Europe

Market prices rose in Europe

Sources: European power exchanges (for Italy: Prezzo Unico Nazionale, or PUN)


Prices rose again across Europe in 2018. Increases were more moderate in France than in neighbouring countries (with the exception of Spain), ending the year up by an average €5/MWh relative to 2017.

Prices were notably higher than in previous years during the summer months, when fuel prices (gas and coal) and the CO2 price were all up. Moreover, a warm and dry summer in Europe, including a few spells of intense heat, drove up consumption while sharply reducing hydropower generation in Nordic countries. High temperatures also led several European nuclear plants to curb power output due to environmental constraints relating to the temperature of water used to cool reactors (rivers, seawater).

A cold spell that settled across Europe at the end of February also pushed prices up. Prices in France were above €150/MWh on four days in November and hit a high for the year of €259.95/MWh on 21 November at 6:00 pm, when temperatures were below normal for the season. At the same time, the availability of the Belgian nuclear fleet was sharply reduced by extended maintenance in the fourth quarter (of the total 6 GW installed, 2 GW or less was available), putting further stress on the European power system.

Conversely, the number of hours during which prices were negative increased to 11 in France including seven on 1st January alone. On that day, prices fell as low as -€31.8/MWh, a record low since 2013. Episodes of negative prices are much more frequent and pronounced in Germany, notably because the country’s electricity mix includes more non dispatchable capacities.

Weekly trend in average spot prices


Why do prices sometimes fall into negative territory?

Negative prices are rare, occurring mainly due to a combination of low demand (overnight, bank holidays, weekends, etc.) and high non-dispatchable generation (wind, solar). It can in some cases be more expensive for a producer to stop and then restart facilities than to have prices be negative for a time. Negative prices primarily occur when must-run renewable sources (wind and solar) cover a large share of demand, which is most often seen in Germany.

Number of hours with negative prices in France and Germany France – Germany



Market coupling guarantees optimal use of cross-border capacities

Day-ahead price coupling makes the European market more economically efficient. It enables the creation of a single trading area, and thus identical price zones when interconnection capacities do not limit cross-border exchanges. France has completed market coupling with most Western European markets over the past decade, and the coupled area was further expanded to include Croatia on 20 June 2018 and Ireland on 1st October 2018.

Note: Germany and Luxembourg form a single bidding zone. Coupling with Poland is exclusively via Sweden (SwePol submarine cable).

Closer look


A remarkable example of convergence occurred on Monday 26 March, between 2:00 and 3:00 am, when prices were identical across the entire coupled area except in Great Britain. Prices in 29 zones converged at €38.92/MWh, from Portugal all the way to Finland. This was the greatest example of convergence ever. It occurred because market conditions were similar in all countries, so interconnections did not limit trading across borders.


A new price zone in Austria

The CWE region, within which market prices for electricity have been coupled since 2010, includes France, Belgium, Germany, Luxemburg and the Netherlands. France, the Netherlands and Belgium each have a price zone for their border, whereas Germany, Austria and Luxemburg were combined in a single price zone. On 1st October 2018, this price zone split into two, one including Germany and Luxemburg and the other Austria. As a result, while the number of countries in the CWE region has not changed, the number of zones with their own prices has risen from four to five.



Slight decrease in price convergence within the CWE region

Number of different prices within the CWE region (% of time during the year)

Cases of price convergence within the CWE region decreased slightly to 33%, reflecting a wide range of situations. In the week of 30 July, prices converged during 89% of one-hour periods (the highest level in seven years). During some other weeks, when market conditions varied greatly between zones or were stressed, for instance during cold spells, prices did not converge across the region during a single one-hour period.


Additional indicators relating to price convergence

Average price spreads between France and Great Britain and Italy were larger than in 2017 as these countries saw steeper price increases than France. The convergence rate was consequently lower.

Spreads distribution between France and its neighbours in 2018


Net commercial exchanges

France becomes again the biggest exporter in Europe

France’s exchange balance reached 60.2 TWh in 2018, which was higher than in the two previous years. It imported 26.1 TWh and exported 86.3 TWh. The balance was positive during every month, and hit 7.85 TWh in May, the highest level on record since July 2014. became again the leading exporter in Europe, after more moderate price growth in the country boosted its exports. Indeed, exchanges between France and neighbouring countries depend directly on price differences between them.


Exchanges remained very volatile throughout the year: France had a net import balance of 10 GW on 28 February at 8:00 am and a net export balance of 16.2 GW on 22 January at 3:00 am. This represents 26 GW of flexibility for the French power system, and also illustrates the level of European solidarity made possible by interconnections.


What is the difference between physical and scheduled commercial exchanges?

Scheduled exchanges between countries are the result of commercial transactions between market participants. Physical flows correspond to the electricity actually carried over interconnector lines directly linking countries.

For instance, a commercial programme for imports on the Franco-Swiss border may be “counterbalanced” by significant exports to Italy, though from a physical standpoint a portion of the power will go through Switzerland after it leaves France. For a given country, the balance of physical flows across all borders and the balance of scheduled commercial exchanges with all neighbours are identical.



Decline in the number of days of net imports

The number of days on which France was a net importer of energy declined to 17 from 52 in 2017. This decrease mainly reflected greater availability of the nuclear power plants than in 2016 and 2017.

Number of days with an import balance on scheduled commercial exchanges

Number of days with an import balance on scheduled commercial exchanges


The flow-based coupling method

Flow-based coupling within the CWE region went live on 21 May 2015.

Previously, these four bidding zones were coupled on a Net Transfer Capacities (NTC) basis, meaning that limitations on exchanges were set bilaterally for each border (one constraint per border and per direction, implicitly taking into account the network situation).

Constraints now explicitly take into account the physical network infrastructure in the five countries. Cross-border exchanges are thus optimised to reflect the actual physical capacities of networks as accurately as possible. This requires very close coordination between the transmission system operators in CWE countries.

In sum, it is no longer possible to consider borders separately, and indicators previously used for the France-Belgium and France-Germany borders have been replaced by France-CWE region indicators.

CWE region



France becomes again a net exporter to CWE

High/low weekly France-CWE exchange balances

After being a net importer for two years in a row, the trend reversed in 2018, with France exporting a net 6.1 TWh. This notably reflected greater availability of the French nuclear fleet, good hydropower generation in the country and numerous instances of unavailabilities of Belgian nuclear power plants late in the year. Exports were particularly robust in May and June, when they hit record highs of 2.64 TWh and 2.56 TWh. On the other hand, France was a net importer during the winter months, as temperature-sensitivity drove its electricity needs up.

Monthly exchange balances with the CWE region


Daily exchange balances between France and the CWE region in 2018

Spain

France-Spain exchange capacities

Average available capacity on the France-Spain border was 2,546 MW for exports and 2,190 MW for imports.

Capacity availability continues to limit exchanges 75% of the time (62% of the time for exports and 13% for imports).

Since the HVDC Baixas-Santa Llogaia line was commissioned in 2015, saturation of the interconnection has decreased, falling from 87% in 2015 to 70% in 2016 and 75% in 2017.

Improvements are still being made including the introduction of a coordinated capacity calculation in 2019 and, longer term, the Bay of Biscay project, which involves building a new underground and underwater interconnection line to double exchange capacities between France and Spain.

More information about the Bay of Biscay project can be found here.


High/low France-Spain exchange balances by month


France still a net exporter

France once again ended the year with a high export balance of 12 TWh, though this was slightly lower than in 2017, reflecting an increase in hydropower generation in the Iberian Peninsula.

France was a net importer on its border with Spain in March, when Spanish wind power generation was particularly high, and in November, when market conditions were less favourable in France.

Monthly exchange balances with Spain

Capacity and daily exchanges between France and Spain, 2015 to 2018


Use of the France-Spain interconnection for day-ahead exchanges in 2018


Italy

France’s export balance with Italy remained high and increased further in 2018, ending the year at 18.5 TWh. The interconnection was mostly used for exports: there were only 330 one-hour periods with net imports (less than 4% of the time), down from 452 in 2017.

The interconnection was saturated 82% of the time, almost always for exports. The anticipated commissioning of a new interconnection (Savoy-Piedmont project) late in 2019 will help boost exchange capacities and opportunities for mutual electricity assistance between France and Italy.

Monthly exchange balances with Italy

Italy caps imports on days when demand is low, especially weekends in the spring and summer. This is because it must keep in service enough thermal power plants that can adjust their output to ensure the stability of the power system. On days when photovoltaic seems likely to cover a large share of demand, import capacity at interconnections is reduced.


Capacity and daily exchanges between France and Italy in 2018


Switzerland France’s export balance with Switzerland increased to 10.6 TWh in 2018. July was the only month during which France was a net importer, as exchanges are usually more balanced in summer (when Switzerland’s hydropower generation increases).

Monthly exchange balances with Switzerland


Capacity and daily exchanges between France and Switzerland in 2018


Great Britain

France’s export balance with Great Britain ended the year at 13 TWh, an increase from 2017 even though exchange capacity was limited to 1.5 GW between 9 March and 5 May due to the partial unavailability of the France-England interconnection (IFA) following an incident on a cable.

The line was used very little for imports from Great Britain to France, with the notable exception of the cold spell of late February/early March and the week of 19 November, when prices were high in France. The line was only used for imports during 493 one-hour periods, down from 1,947 in 2017.

Monthly exchange balances with Great Britain

Capacity and daily exchanges between France and Great Britain in 2018


Evolution of cross-border exchange mechanisms

RTE is supporting the evolution of cross-border mechanisms

From the beginning, RTE has been working with market participants, in accordance with the principles set forth in European network codes, to develop mechanisms that encourage the opening of the French electricity market and its integration within Europe:

With the EU’s Capacity Allocation & Congestion Mechanism (CACM) regulation in effect, there is competition in France between different exchanges (EPEX Spot, which has long operated in France, and Nord Pool). These operators, called NEMOs (Nominated Electricity Market Operators), are designated by regulators in each country. Already in place for intraday coupling following the launch of the XBID platform in June 2018, competition will be expanded in 2019 via day-ahead coupling.

Coordinated calculation processes, complying with the objectives set forth in the CACM regulation, will be introduced for intraday trading at the France-Italy border and for day-ahead capacity on the France-Spain border in 2019.

Following implementation of the EU Regulation on Forward Capacity Allocation (FCA), a process will be developed for the coordinated calculation of forward capacity at the France-Spain border in 2019.

To integrate the changes resulting from the EU’s Electricity Balancing (EB) regulation, the TERRE (Trans European Replacement Reserve Exchange) project will include a common platform over which several European countries can trade balancing energy with an activation time of under 30 minutes.


Flexibility

Activities of the balance responsible parties

Markets are tools for optimising the power system

RTE works around the clock, seven days a week, directing electricity flows over its lines to ensure that generation and consumption are always balanced at the least possible cost to society. This balance is achieved through a series of decisions aimed at optimising the power system, from the long term down to real time. These decisions are taken by private actors, whose actions are coordinated thanks to the market mechanisms through which their activities are rewarded.

Increasing the flexibility of the power system is also clearly identified as key to a successful energy transition, notably given the intermittent nature of renewable energy sources. RTE’s market rules are well-suited to the participation of new, flexible capacities, as they allow all operators to be rewarded for their capacity and energy via markets (demand response, storage, renewable energy sources, etc.).


The balance responsible party system allows consumers, producers, suppliers and traders to conduct all types of commercial transactions in electricity markets, on timeframes ranging from several years ahead to almost real time. Thanks to the flexibility this system provides, market participants can respond to a wide variety of contingencies and uncertainties. Each balance responsible party creates an activity portfolio and agrees to settle the costs resulting from imbalances between generation and consumption within that portfolio, as recorded after the fact. The parties have a financial incentive to maintain a balance within their portfolios and thus contribute to the balance of the French power system.

As of 31 December 2018, there were 176 balance responsible parties with valid contracts. Of these, 147 were active during the year and 43 made significant injections or withdrawals.

Activities of the balance responsible parties

Closer look


Transactions conducted by balance responsible parties on markets

Transactions between balance responsible parties increased relative to 2017, notably on the EPEX Spot France exchange, where trading volumes were up by nearly 8%.

Intraday transactions rose further, ending the year about 9% higher. These mechanisms give balance responsible parties flexibility to operate as close as possible to real time. Their need for flexibility is notably increasing in line with growth in the share of renewable energies in the mix, as generation from these sources is more difficult to forecast.

Intraday transactions conducted by balance responsible parties


Record ARENH purchase volumes

In 2018, ARENH purchases totalled 87.1 TWh (excluding losses), an all-time record

(the ceiling is set at 100 TWh). The fixed ARENH price of €42/MWh (including

capacity certificates) was competitive throughout the year relative to market prices,

which were already high in the latter months of 2017 and rose further in 2018. A total

of 85.4 TWh were requested during the first gate of December 2017, and then another

1.8 TWh during the second gate in June.

The ARENH mechanism

The Regulated Access to Historical Nuclear Electricity scheme (Accès Régulé à l’Electricité Nucléaire Historique – ARENH) was established by the NOME Act on the new organisation of the electricity market.

To guarantee fair competition in the power market, alternative suppliers have the opportunity to buy a portion of EDF’s nuclear generation at the ARENH rate. The rate was set by the government at €40/MWh between 1st July and 31st December 2011 and then at €42/MWh since 1st January 2012. Effective 1st January 2017, the price also includes the related capacity guarantees for each delivery year (see page on the capacity mechanism).

The Energy Code stipulates that suppliers’ total demand for ARENH electricity cannot exceed 100 TWh a year (excluding supply of losses by system operators), which represents about a quarter of EDF’s total nuclear power production in France. Electricity suppliers seeking to “exercise their ARENH rights” must submit their requests to the CRE (Energy Regulatory Commission).


Balancing mechanism

The balancing mechanism allows RTE to modulate generation, consumption and

exchanges to ensure that electricity supply and demand are always balanced. The

mechanism involves the selection of bids submitted by balancing service providers

based on the merit order and identified needs.



Increase in cross-border balancing

Cross-border balancing volumes rose during the year and accounted for 42% of total upward balancing and 21% of downward balancing. The increase in upward balancing volumes was driven primarily by TSO-Actor exchanges (from Switzerland and Germany), whereas the BALIT share (mainly Spain) fell to 4.9% from 6.4% in 2017. Total balancing volumes reached 8.39 TWh, which was just under 2% of gross consumption in France.

Volumes activated on the balancing mechanism


Tight situations on the balancing mechanism

The number of instances where supply was tight on the balancing mechanism increased in 2018 to a total of 68 half-days. Whereas in 2017 a third of all situations where supply was tight occurred in January, last year the distribution was more even: February, March, June, July, August, October and November all counted at least five half-days when supply was short.

The factors that can cause such imbalances include social movements at generation plants, environmental constraints (reduced output at nuclear plants during summer heatwaves) and cold spells.

Situations of supply-demand imbalance (number of half-days)

NB:

.


Average costs on the balancing mechanism

Average costs on the balancing mechanism

Note: Average costs include potential start-up costs.

RTE updating its real-time reporting on the system

To make it easier to understand the actions it takes to guarantee security of supply and to let the market regulate itself as much as possible, RTE is making changes to its publications on power system margins and the messages it sends to market participants prior to taking action.

On the Customers’ Portal page of its website, RTE will publish the following information every day, on a day-ahead basis and with an update during the day:

– On the one hand, the difference between production and the imports scheduled by market participants as notified to RTE, and, on the other hand, RTE’s consumption forecast along with the exports scheduled by market participants,

– The system margin at peak demand times of 1:00 pm and 7:00 pm if it is below the level required, in which case RTE will notify markets that additional generation or demand-response offers are needed,

– The margin at two hours from real time (when RTE alone can take action) which, if below the level required, will prompt RTE to notify markets of the activation of additional offers.


The Energy Code (article L271-1) defines demand response as an action intended to temporarily reduce, in response to a one-time request sent to one or more consumers by a demand response operator or electricity supplier, the electricity effectively withdrawn from the public transmission or distribution network at one or more consumption sites, relative to a consumption plan or consumption estimate.

Market players can use demand response to optimise their own portfolios or to sell energy directly to other players or to RTE. There are two main categories of demand response that contribute to the supply-demand balance:

Industrial demand response, when consumption is reduced at one or more industrial sites (either by shutting down processes or by switching over to own consumption). This type of demand response can be proposed either directly by the industrial user or through an aggregator or supplier.

Distributed demand response, or the aggregation through an aggregator or supplier of individual demand response actions involving smaller volumes, all carried out at the same time by residential or professional customers.

Learn more about demand response in our magazine Mag RTE & Vous

Demand response



Demand response is remunerated through a variety of mechanisms

France was the first country in Europe to open all parts of its national market to all consumers, including those connected to the distribution networks:

Since 2003, it has been possible to offer industrial demand response on the balancing mechanism.

Since 2008, RTE has been contracting with BRPs for demand response capacity to guarantee the availability of their capacity to the balancing mechanism.

Since 2011, RTE has been contracting demand response capacity that can be activated on very short notice for the mFRR (manual frequency restoration reserves). In 2018, demand response capacity made up more than half of the rapid reserve.

Since January 2014, it has been possible to sell demand response energy directly on energy markets through the NEBEF mechanism.

Since July 2014, industrial customers have been able to participate in frequency ancillary services by offering demand response (1 MW minimum). These reserves, which can be automatically activated in timeframes ranging from a few seconds to a few minutes, are critical to keeping supply and demand balanced. Previously, only generation facilities could participate. In 2018, demand response capacity contributed 10% of the FCR (frequency containment reserve).

In 2018, demand response tenders became a support mechanism for the demand response sector. Organised by the Ministry of Energy, the tenders encourage the creation of demand response capacity to meet the targets set forth in the multiannual energy programme.


Demand response on the balancing mechanism

The average demand response volume offered on the balancing mechanism was 727 MW, in line with 2017.

A total of 22 GWh of demand response was activated on the balancing mechanism, primarily in the winter, during the cold spell in week 9. The 1st of March alone accounted for 6 GWh, a record for a single day.

Demand response volumes on the balancing mechanism

On the 1st of March, more than 1,000 MW of demand response was requested on the balancing mechanism, the highest value ever.

Demand response capacity activated exceeded 100 MW on 15 days in 2018.

Maximum demand response activated each day on the balancing mechanism


The NEBEF mechanism

The NEBEF mechanism (Demand Response Block Exchange Notification) allows market actors to realise value on demand response directly through the market. They inform RTE of the demand response they plan to activate the next day and can now re-declare schedules at the intraday scale. RTE verifies afterward that the volumes correspond to the schedules submitted by participants. To date, 23 demand response operators have signed contracts with RTE to participate in the mechanism.

Demand response volumes selected reached 27 GWh, which was lower than in 2017 but higher than in 2016. A significant gap was notably observed between January 2018 and the same month in 2017, when supply was tighter and prices were higher. There were few instances of significant demand response volumes being activated (more than 100 MW) but distributed demand response volumes increased.

Demand response volumes on the NEBEF mechanism

Note: .


Tariff-based demand response

Traditional tariff-based demand response

Special tariffs have been created to help maintain the supply-demand balance, notably during load peaks in winter, focusing on the demand side rather than supply to limit the load.

“EJP” (Effacement Jour de Pointe – demand response during peak days) tariffs, introduced in the 1980s, involved raising supply prices in times of system stress but not for more than 22 days a year and only during the winter months. Users have not been able to sign up for these tariffs since 1998, and their effects have been diminishing ever since. “Green” and “yellow” regulated tariffs were phased out on 1 January 2016, and the corresponding contracts have been terminated. Former customers had to sign new non-regulated contracts with or without a demand response component. They have also been able to realise value on demand response through market mechanisms.

Other demand response tariffs for the mass market (professional and residential customers) were introduced in the 1990s thanks to the Tempo signal. RTE has been managing this signal since 1 November 2014 and providing information about it through the éCO2mix website to allow all suppliers to propose contracts that include demand response. Lastly, suppliers create and make available to their remote-read customers commercial offers that may include demand response clauses with specific conditions.

Suppliers have estimated the demand response capacity made available through these different tariff-based mechanisms in 2018 at close to 700 MW.


EcoWatt, a voluntary scheme available in the French regions

EcoWatt is a voluntary scheme introduced in Provence-Alpes-Côte d’Azur and Brittany in the late 2000s, to address the specific problems faced by local power systems. Since “safety nets” were introduced and smart electric grids were rolled out – SMILE (Bretagne-Pays de la Loire) and FLEXGRID (PACA) – the EcoWatt scheme has become a tool for supporting the energy transition and the French regions. Conducted in partnership with the French government, Ademe, Enedis and local governments, the EcoWatt scheme now counts close to 90,000 subscribers in these two regions.

EcoWatt provides citizens with an electricity barometer they can use to check local consumption forecasts at any time of the day. These forecasts are provided with colour-coded signals: green if demand is reasonable, orange if it is high and red if it is very high. People then have a fun way to help tackle the challenge by taking actions that reduce their electricity consumption.

Learn more about the scheme here: www.monecowatt.fr.


Trend in demand response capacity

Trend in demand response capacity offered on the balancing mechanism per week

Note: The minimum capacity (respectively maximum) offered corresponds to the half-hourly periods of the week where the sum of all capacity offered is the lowest (respectively the highest).


Detailed NEBEF indicators

Maximum demand response each day on the NEBEF

Note: .

Total demand response activated during the year per half-hourly period and average value at spot price


Capacity mechanism

Launch of the capacity mechanism in France

The goal in implementing a capacity mechanism in France is to guarantee security of supply over the medium term by covering risks during peak periods in winter. It was approved with conditions by the European Commission on 8 November 2016, and then by the French Ministry of Energy and Energy Regulatory Commission on 29 November 2016.

2018 was the second delivery year for the mechanism.


How the capacity mechanism works

The capacity mechanism rests on two pillars. First, it creates a requirement for obligated parties – mostly electricity suppliers – to obtain capacity certificates to contribute to the security of supply of their customers. Holding suppliers responsible in this way is notably a way to contain peak demand growth by creating an economic incentive to limit their customers’ consumption.

Second, RTE certifies the capacity of operators that agree to make their capacity available when demand peaks in winter. The capacity mechanism allows them to realise value on the availability of generation and demand response capacity by selling capacity certificates.

Actors trade capacity certificates through auctions or OTC transactions. During the delivery year, RTE notifies them of the peak days when they must uphold their individual commitments. After the delivery year, RTE informs suppliers of their final obligation level and calculates the actual availability of their capacity. Differences result in financial payments.

Closer look


Forward indicators for the capacity obligation

RTE’s capacity obligation forecasts for 2019 are presented in the table below:

Demand variants in the Generation Adequacy Report

Forecast total capacity obligation for France in 2019 (GW)

High scenario 94.2

Intermediate scenario 3 93.7

Intermediate scenario 2 93

Low scenario 92.7

Suppliers can take measures to reduce their customers’ consumption. Total demand response measures are published in the Registry of Consumption Control Measures.


Breakdown and level of certified capacity

Note: The figures for 2018 are different from those in the chart in the 2017 Annual Electricity Report because actors can re-declare their available certified capacity throughout the delivery year.

Certified entities and their production methods are defined at the site level.

Certified volumes for 2019 total 89.7 GW. For the purpose of transparency, exchange volumes and prices (€/certificate) are published on the EPEX SPOT website.

The reference market price for the delivery year (DY) is defined, per the methodology created by the CRE, as the simple arithmetic average of prices revealed by auctions on organised exchange platforms between the 1st of January in DY-4 and the 31st of December in DY-1.

Delivery year Reference market price

2017 €9,999.8/MW

2018 €9,342.7/MW

Details of these transactions can be found in the capacity certificates register.


Evolution of the capacity mechanism

Revising the mechanism rules was the last step in bringing it into compliance with the European Commission decision of 8 November 2016 relative to State aid. The new capacity mechanism rules took effect on 29 December 2018, after being approved by the ministerial order of 21 December 2018 defining the rules for the capacity mechanism and taken in application of article R. 335-2 of the Energy Code and the decision of the Energy Regulatory Commission of 20 December 2018.

To bring the mechanism into compliance with the European Commission decision, the following adjustments were made:

Explicit participation of cross-border capacities in the mechanism, Long-term tenders for new capacities.

Steps were also taken to simplify and improve the operation of the mechanism in the following areas:

Capacity obligations, Certification, New sources of flexibility, Functioning of the capacity market.


The transmission network

How the network evolved in 2018

Length of lines

With 105,857 km of lines in service, the transmission network continues to guarantee security of supply in the territories and regions while facilitating and supporting the accommodation of renewable generation.

Highlights of 2018 included the completion of the “2 Loires” project (restructuring of power supply between Le Puy-en-Velay and St-Etienne), the creation of a 225/63 kV substation in Saône (to secure the supply of electricity to the Besançon area), and the start of work on the terrestrial portion of “IFA2” (new interconnector between France and England).

New underground lines (newly created or overhead lines newly undergrounded) totalled 223 km, while 588 km of overhead lines were taken down (permanently or to be replaced) during the year.

All in all, the length of the network decreased by 104 km year-on-year in 2018.


Length of lines in service (km) Overhead Underground Total

At 31 December 2017 99,964 5,997 105,961

New 546 249 795

Newly added 125 204 329

Replaced 421 26 447

Overhead lines buried 0 19 19

Scrapped -588 -18 -606

Other (placed in reserve, length adjustments, etc.)

-267 -26 -293

At 31 December 2018 99,655 6,202 105,857

Change 2018/2017 -309 205 -104

Change in length of lines in service

The total length of underground lines in service ended the year at 6,202 km, topping the 6,000 km mark for the first time.


At the same time, the total length of overhead lines on the transmission network continued to decrease, falling to 99,655 km.


Substation connections

A total of 24 new substations were connected to the public transmission network in 2018, including 16 very high voltage substations. A 225/63 kV substation was notably commissioned in Saône, in the Doubs, to help guarantee security of supply to Besançon. The 225/90 kV Hérie-la-Viéville substation was also commissioned in the Aisne to facilitate the accommodation of renewable generation.

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New and replaced lines

A growing portion of RTE’s lines are underground

More than 348 km of new lines were added to the public transmission network in 2018 (including overhead lines that were undergrounded).

Similarly to 2013 (with the 400 kV Cotentin – Maine line) and 2016 (400 kV Lonny – Vesle line), 2018 stood out from other years thanks to the completion of a very high voltage overhead project (the “2 Loires” project and the commissioning of the 225 kV Rivière – Sanssac and Pratclaux – Trevas lines, together spanning 75 km). Besides this project, nearly all the new lines built in 2018 used underground technology, as has been the case for about ten years.

RTE also replaced more than 447 km of overhead and underground lines on its network.


Overhead and underground lines: Complementary technologies

A variety of solutions are leveraged to expand the transmission grid, taking into account technical, economic, environmental and societal factors. Two techniques are used: overhead and underground.

As part of its public service contract, RTE has committed to not increase the total length of overhead lines (removals offset additions) and to place at least 50% of new HV lines underground.

Investment costs for overhead and underground lines depend on voltage levels: costs are the same for 63 and 90 kV, but underground lines cost about twice as much as overhead lines for 225 kV and eight times as much for 400 kV (*).

Underground lines currently represent:

8.3% of all 63/90 kV lines, 5.5% of all 225 kV lines, a negligible share of 400 kV lines (0.02%).

(*) Underground cables for 400 kV AC are quite expensive and substations must be installed every 20 km to offset the capacitive effect of the cables. At this voltage level, buried DC lines can be an option. The cost is the same as for an overhead AC line but transmission capacity is three to five times lower.

Source: Ten-Year Network Development Plan



400 kV and 225 kV

Underground

A total 30 km of new 400 and 225 kV underground lines were brought into service in 2018. The main completions were:

The 225 kV Château-Gombert – Enco-de-Botte double-circuit line in the Bouches-du-Rhône, as part of the plan to connect the Château-Gombert customer distribution substation, notably to enhance security of electricity supply to the Marseille area,

A portion (nearly 8 km) of the 225 kV La Rivière – Sanssac overhead/underground line as part of the “2 Loires” project (see Highlights).

Overhead

RTE replaced conductors on nearly 224 km of overhead lines operated at voltages of 400 kV and 225 kV during the year. Key completions included:

The upgrading of the 225 kV St-Auban – Ste-Tulle and Oraison – Sisteron lines in Alpes-de-Haute-Provence to increase their transmission capacity so that they can accommodate more renewable generation going forward,

The replacement of the towers and conductors on the 225 kV Niort – Val-de-Sèvre line in the Deux-Sèvres,

The replacement of some conductors on the 400 kV double-circuit Le Havre – Rougemontier line.


63 kV and 90 kV

Underground

The length of underground lines operated at voltages of 63 kV and 90 kV increased in 2018, as 193 km of new lines were added. RTE notably brought into service:

The 90 kV Le Laitier – Rom line in Deux-Sèvres (to address the distribution of load growth across different areas and the elimination of transmission constraints observed on the Poitiers-sud network),

The 90 kV Herie-la-Vieville – Marle line in the Aisne (strengthening of the network to accommodate new renewable generation),

The 63 kV Boutre – Cadarache line in the Var (to boost security of electricity supply to the CEA customer site in Cadarache),

The 63 kV Scheer – Selestat line in the Bas-Rhin (part of the plan to strengthen the grid in the centre of Alsace),

The 63 kV Athélia – le Castellet line in the Bouches-du-Rhône and Var (to enhance security of electricity supply to the coastal area between Marseille and Toulon),

The 63 kV Breteuil – Hargicourt – Valescourt line in the Oise (restructuring of power supply to the central part of the Oise).

The undergrounding rate for new 63 kV and 90 kV lines was 93.2% in 2018 and has averaged 97.4% over the past three years (2016-2018).

Undergrounding rate for 63 kV and 90 kV lines


Overhead

Conductors were replaced on 138 km of 63 kV and 90 kV overhead lines. Examples included:

The 90 kV double-circuit Juine – St-Evroult line in the Essonne, The 90 kV Cerizay – Mauleon line in the Deux-Sèvres, The 90 kV la Farradière – le Thou line in Charente-Maritime, The 63 kV Betting – St-Avold line in the Moselle, The 63 kV la Chapelle-du-Châtelard – Cize – Servas line in the Ain, The 63 kV Bagatelle – Bram – Castelnaudary – Valgros line in the Aude.

Nearly 14 km of new lines were brought into service during the year, including 10 km on the Argentière – Briançon link in the Hautes-Alpes, as part of the plan to boost security of electricity supply to the Haute-Durance.


2018 highlights

Completion of the “2 Loires” project

The commissioning of the new 225 kV Rivière – Sanssac and Pratclaux – Trevas lines marked the completion of the “2 Loires” project launched in 2015.

Built in 1941, the 225 kV line between Le Puy-en-Velay, Yssingeaux area and Saint-Etienne served several urban and industrial centres in the Loire and Haute-Loire departments. It had reached its technical limits after 70 years, especially given the changes taking place in the region. The “2 Loires” project involved replacing the existing line with a new higher-capacity 225 kV double-circuit line and adjusting its route to reflect the region’s new needs.

To learn more, please see the report on this project in RTE’s magazine MAG RTE&Vous.


Construction of a 225/63 kV substation to boost security of supply to Besançon

Of the new substations connected to the transmission network in 2018, the one in Saône, in the Doubs department, is a good illustration of RTE’s mission of strengthening the grid and supporting regional development. Three years of work preceded the commissioning of the new substation in September 2018. Improvements were made to the 63 kV and 225 kV lines connected to the substation as part of the project.

This substation stands out in that it is in the first one in the region to integrate from the start the “zéro-phyto” concept, meaning, among other things, that no phytosanitary products were used, the carbon impact of work was limited, the project was tracked by an environmentalist, and innovative mulching and plant coverings were used to reduce maintenance requirements.

Start of work on the new France-England interconnection (IFA2)

In June of 2018, construction started on the converter station for the new France-England interconnection. This major project (IFA2) is being carried out in cooperation with UK transmission system operator National Grid. Work has begun on the underground line. With the civil engineering portion of the project completed, the cables are expected to be laid in 2019 so the line can go live in 2020.


Ten-Year Network Development Plan

For more information about network development, see the Ten-Year Network Development Plan

Map of main projects completed

Closer look


Main projects brought into service in 2018


RTE investments

RTE invested close to €1.45 billion in 2018

RTE’s investments within the scope of businesses regulated by the CRE (Energy Regulatory Commission) totalled €1,447 million in 2018. Investments primarily focused on completing the upgrading of the 225 kV line between Cergy and Persan to 400 kV; securing supply to the Préguillac area (225 kV Préguillac-Saintes and Farradières-Saintes lines); continuing work on the new interconnector with England (“IFA2”) and the DC interconnection between France and Italy passing through the Fréjus safety tunnel (“Savoy-Piedmont” project); and restructuring the 225 kV network in Haute-Durance. Some 60% of RTE’s grid investments went to existing infrastructure.

RTE investments

RTE has submitted to the regulator a €1,641.6 million investment programme for 2019. The proposed increase in investments from 2018 reflects a combination of: higher spending on interconnections (ramp-up of IFA2, further work on Savoy-Piedmont), the development of major domestic projects (including Avelin-Gavrelle and the start of work to connect offshore windfarms), faster digitalisation of substation control systems, the same level of investment in guaranteeing security of supply and facilitating assistance between regions (because consumption has been stable), and continued investment in information systems and real estate.


RTE is planning its investments knowing that sustained efforts will be required over the coming years to ensure a successful energy transition. Indeed, the French transmission network will play a key role in accommodating new generation sources, including offshore wind power, and in integrating the European energy market by boosting cross-border exchange capacity.

Moreover, RTE is responsible for ensuring the operational safety of the networks and continuity of supply to the different consumption areas and regions. It is adapting its investment strategy to the major changes the power system is undergoing, giving preference to digital solutions that enable optimal use of existing infrastructure.

Digital technologies will allow RTE to optimise decisions about grid operations, maintenance and upgrades. Its investment programme for the coming years aims to make RTE the leading European TSO in terms of power and digital technologies.

A total of 51% of the projects planned for the 2017-2020 period are designed to improve security of supply and nearly 30% to prepare for the new electricity mix. Developing new interconnections will capture 14% of investments and another 6% will go to projects that will make the power system safer.

Breakdown of grid investments by end-goal (2017-2020)

To keep pace with these changes, RTE focuses in priority on adapting existing infrastructure. Nearly 60% of the investments planned involve renovating or upgrading the existing grid.

RTE also intends to develop the digital technologies that will allow it to optimise decisions about managing, maintaining and upgrading the grid. They must in all cases be rolled out with high voltage infrastructure.


RTE standing up for the environment and biodiversity

RTE is taking action to reduce the environmental impact of its activities by utilising resources and energy more efficiently. For instance, in 2004, RTE launched an initiative to reduce leakage of SF6, which has a strong greenhouse gas effect. SF6 is currently used to insulate high-voltage equipment. It can be found in SF6 circuit breakers (found in most overhead transformers) and gas-insulated substations, whether inside buildings or outdoors. SF6 emissions reached 5.9 tonnes in 2018. Implementation of a leak recovery solution is expected to translate into further progress. Compared with the 2008 level, emissions have been cut by almost 15.7%.

RTE is also forging partnerships to turn its power line corridors into corridors of biodiversity. Nearly all of RTE’s infrastructure is located in agricultural areas (70%) or wooded regions (20%), and some 23,000 km of power line corridors cross through protected natural areas.

Protecting and encouraging the development of biodiversity are 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.

In 2018, RTE developed a total of 1,043 hectares as biodiversity-friendly areas through partnerships with local players, strengthening the company’s roots in the French regions.

Detailed sustainable development information can be found in RTE’s Management Report.


Ten-Year Network Development Plan

For more information about network development, see the Ten-Year Network Development Plan

Map of main projects under way

Closer look


Main projects under way


Bay of Biscay

The Bay of Biscay project involves creating a new interconnection between France and Spain. Scheduled to go into service in 2025, it will boost exchange capacity between France and Spain to almost 5,000 MW. This new 370 km link will run from the substation in (near Bordeaux) to the one in (near Bilbao), and will be the first France-Spain interconnection that is partially underwater.

Haute-Durance project

Power is supplied to Haute-Durance primarily via a single 150 kV line built in 1936. The region now finds itself in a vulnerable position, particularly when power demand peaks in winter. RTE has thus designed a programme divided into six projects. It involves creating a 225 kV network to replace the existing 150 kV network and upgrading the 63 kV network (undergrounding, reconstruction or strengthening) all while protecting the local environment. The programme is being carried out through 18 work projects that will be staggered over time until the last segment is completed in 2020.


Connecting offshore windfarms

France’s Multiannual Energy Programme calls for the installation of 3,000 MW of offshore wind capacity by 2023. Offshore development offers significant power generation potential given the country’s natural assets (11 million km of water in its jurisdiction). The highest-potential areas are concentrated off the coasts of Normandy, Brittany and Pays de la Loire. The government has launched two tenders for the construction of offshore windfarms in these areas, followed by a third launched late in 2018 for one off the coast of Dunkirk. RTE is in charge of studies and connecting these farms to the grid. The solution being considered involves creating 225 kV double-circuit lines, starting out underwater between the windfarm connected to the offshore substation and the landing point and then running underground between the landing point and the 225 kV substation where they are earthed.

The sites selected through the first call for tenders have already been the subject of consultations with local stakeholders, government services and infrastructure operators to determine the best possible path for the lines from a technical, economic and environmental standpoint. Late in 2015, public inquiries were launched for the projects in the towns that will be affected by the future Fécamp, Courseulles-sur-Mer, Saint-Nazaire and Saint-Brieuc windfarms. Production is not scheduled to start at these sites until 2021.


Development of flexible solutions

Technological and digital innovations are creating opportunities to develop the public transmission network in new ways and meet the challenges posed by the energy transition. There is great uncertainty about trends in local consumption and generation, and the expansion of renewable energy production makes it necessary to manage variability.

RTE is taking these new challenges into account by integrating flexible solutions into the grid, for instance via automated peak shaving/generation capping. It is also experimenting with next-generation substations (click here for more information).

The IFA2 project

Conducted in cooperation with UK transmission system operator National Grid, the IFA2 project (construction of new France-England interconnection) is part of the plan to support the energy transition and enhance security of electricity supply in both countries.

The project involves creating a DC line around 225 km long between Tourbe, which is located south of Caen, and Fareham in England. Converter stations at both ends will transform the DC into AC so the line can be connected to the transmission grid. The future interconnector will have transmission capacity of 1 GW.


Savoy-Piedmont project

This project, which kicked off in the spring of 2015 in partnership with RTE’s Italian counterpart TERNA, involves building a new France-Italy interconnector connecting the substations at Grande-Ile (Sainte-Hélène du Lac) and Piossasco (Turin) via an underground DC line almost 190 km long. The new line will represent a bona fide technological feat and help increase mutual assistance possibilities in Europe by boosting exchange capacity between these two countries by 60%.

The new interconnection is expected to be commissioned in 2019.

The press kit for this project can be found here.


Electricity quality q

Equivalent outage time

Equivalent outage time (temps de coupure équivalent - TCE) is one of the indicators used to measure the quality of the electricity RTE supplies. In 2018, equivalent outage time was 2 min 59 sec, excluding exceptional events. This result was in line with the average of the past ten years, albeit above the 2 min 48 sec limit set forth in the incentive regulation.



Outage frequency

Outage frequency has been factored into the incentive regulation set by the CRE since 2013 to encourage continuity of supply. In 2018, outage frequency was 0.42 outage/site, excluding exceptional events. This was within the 0.46 limit set forth in the incentive regulation and below the average for the past ten years.

Outage frequency


A robust network that held up well during a year of exceptional storms

Lighting density is a leading cause of the brief outages observed during the year, and it has a non-negligible impact on the outage frequency indicator.

In terms of storms, 2018 was an exceptional year: with close to 725,000 cloud-to-ground lightning strikes and 296 days of storms, France was hit by lightning more times in 2018 than in at least 30 years (source: Météorage), with lightning density ending the year at 1.3 strike per km² across France. The transmission network nonetheless proved robust, as outage frequency stayed within the average of the past ten years.

Lightning density and outage frequency


The regional figures below also show that outage frequency was above average in the regions the most impacted by lightning, particularly the southeast.


Loss rate

The loss rate was stable in 2018

Line losses occur when electricity is moved from generation sites to consumption sites. Loss volumes depend on the power carried, the distance over which it is carried, weather conditions and the characteristics of the grid. Though most of these factors are external, RTE works to minimise losses by making decisions about grid development and operation that optimise the distance over which electricity travels as much as possible. Nearly 80% of losses are due to the Joule effect and Corona effect on high and very high voltage lines. Other effects contribute as well, notably when current passes into transformer substations. The environmental impact of losses corresponds to the power that must be generated to offset them.

In 2018, losses on the RTE transmission network reached 11 TWh, which represented 2.16% of total injections (generation and imports).


Glossary

A

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'Electricité 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

B

Balance responsible party

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 ensure that, at any given time, RTE has sufficient power reserves it can

activate if supply and demand do not balance

BALIT Balancing Inter TSO: Mechanism through which transmission system operators exchange balancing energy for system balancing. It is available for France-Spain and France-UK exchanges.

Business customers

Customers getting power from the public distribution grid with contracted power of 250 kVA or more

C

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

CCGT

Combined-cycle gas turbine

Converter station

Converter stations can convert DC to AC and thus enable its integration into the power system

Corona effect Physical phenomenon occurring when the conductor is exposed to high voltage

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

D

Demand response

Mechanism by which consumers cancel or postpone all or part of their power consumption in response

to a signal

E

EDF-SEI

EDF-SEI is an integrated operator that generates, purchases, transmits, distributes and supplies

electricity in non-interconnected island territories

Enedis

A distribution system operator in France

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


Energy not supplied as a result of customer power cuts, expressed as a ratio to total annual power

supplied by RTE to its customers

Exceptional events

High impact, low probability atmospheric phenomena as well as cases of force majeure

G

Generation: Bioenergy

“Bioenergy” includes biogas, paper/paperboard waste, municipal waste, wood-energy and other solid

biofuels

Generation: Fossil-fired thermal

“Fossil-fired thermal” includes fuels like coal, oil and gas

Generation: Hydropower

“Hydropower” includes all types of hydropower facilities (pondage facilities, run-of-river, etc.).

Consumption resulting from pumping at “STEP” (pumped storage stations) is not deducted from total

output

Generation: Nuclear

“Nuclear” includes all nuclear power plants. Consumption by auxiliary generator sets is deducted from

generation


Generation: Renewable

“Renewable” includes all electricity generated from renewable sources (hydro, wind, solar, bioenergy)

Gross consumption

Power consumed across France, including Corsica and factoring in losses

H

Heavy industry

Final customers getting electricity directly from the transmission system operator

I

Industrial output

The indicator used is based on Insee’s industrial output indices, weighted to reflect power demand in

the different segments of each sector

Intraday

Refers to electricity trades conducted on very short notice, almost in real time

ITER

International Thermonuclear Experimental Reactor

J

Joule effect

Heating of the conductor when an electric current flows through it

L

LDCs

Local Distribution Companies. These are, along with Enedis, 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 km2 in a given region

M

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

Multiannual Energy Programmes

Multiannual Energy Programmes (Programmation Pluriannuelle de l'Energie – PPE) are a new tool

used to set priorities to guide the actions of public authorities as they relate to the energy transition, in

accordance with the commitments outlined in the energy transition law for green growth


MWp

Megawatt peak corresponds to 1 million Watt-peak units. A Watt-peak is a measuring unit for the output of photovoltaic panels, corresponding to the production of 1 Watt of electricity under normal

conditions for 1,000 Watts of solar radiation per square metre at an ambient temperature of 25°C

N NEB

Block Exchange Notification (Notification d'Echanges de Blocs): Service allowing balance responsible parties to exchange energy blocks with other balance responsible parties and/or to supply electricity to consumption sites connected to the transmission or distribution grid outside their balancing perimeter. 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 individual countries’ power grids

O

Outage frequency

Ratio between the number of short or long outages and the number of distributors and industrial customer sites supplied by RTE. An outage is considered short if it lasts between 1 sec and 3 min and long if it lasts more than 3 min

P 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

Professional customers

Customers getting power from the public distribution network for professional use with contracted power of 36 kVA or less

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

R 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 customers

Customers getting power from the public distribution network for residential use with contracted power

of 36 kVA or less Residual demand


Residual demand corresponds to demand from which must-run generation has been subtracted Retail customers

This is another name for the residential sector, which includes customers that get power from the public distribution network for residential use with contracted power of 36 kVA or less

S Seasonal adjustments

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

SMEs/SMI

Final customers to which distribution system operators provide medium- and 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

T TSO

Transmission System Operator

V VPP

Virtual Power Plants: A mechanism that was phased out in the first half of 2015

W Water reserve

The water reserve in France is the weekly average aggregate filling rate of all water reservoir and

hydro storage plants. The upper energy is energy that can be generated from the (only) production unit directly connected to the reservoir, depending on its filling rate. The data published constitutes

only the reserves related to upper energy and is expressed in MWh


RTE - Direction innovation et données – Février 2019

contents...rte – electricity report 2018 9 a year of contrasts 2018 was one of the warmest years...

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