2015 - 2024 - grtgaz · 2015 - 2024. 10 th edition. contents. profile..... 1. framework of the...

Construisons le transport de demain

TEN-YEAR NETWORK

DEVELOPMENT PLAN

2015 - 2024

10th

edition

contentsProfile ......................................................................................................................................................................................................... 1

Framework of the GRTgaz ten-year network development plan ............................................................ 2

Foreword by the managing director................................................................................................................................. 4

Summary ................................................................................................................................................................................................. 5

1. EVOLuTION AND pROSpECTS FOR THE GAS mARkET IN EuROpE 1.1 A new drop in European consumption in 2014 ..................................................................................11

1.2 World prices again contrasted in 2014 ......................................................................................................13

1.3 Stabilisation of supplies ...........................................................................................................................................16

1.4 Uncertainty over long-term demand ............................................................................................................18

1.5 The European energy policy and its objectives ....................................................................................20

1.6 Development of gas infrastructures in Europe .....................................................................................22

1.7 Major European infrastructure projects......................................................................................................24

2. EVOLuTION AND pROSpECTS FOR THE GAS mARkET IN FRANCE 2.1 Diversified supply sources ......................................................................................................................................27

2.2 Decreasing consumptions in 2014 .................................................................................................................28

2.3 The role of gas in the energy transition .....................................................................................................30

2.4 Gas demand forecast.................................................................................................................................................31

2.5 Public service obligations in the event of exceptionally cold spells .....................................34

2.6 The alternative scenarios for the period up to 2030 .......................................................................36

2.7 The transmission offer of GRTgaz ...................................................................................................................43

2.8 Demand for transmission capacity on the GRTgaz network ....................................................45

3. DEVELOpmENT OF THE GRTgaz TRANSmISSION NETwORk

3.1 Developing the transmission network: process and timelines ................................................55

3.2 Project portfolio changes .......................................................................................................................................56

3.3 A single marketplace in France in 2018.....................................................................................................57

3.4 Developments in the North Zone ....................................................................................................................59

3.5 Developments in the South Zone ....................................................................................................................63

3.6 Other development projects ................................................................................................................................66

3.7 Infrastructure to be commissioned over the next three years (2015-2017) ................67

3.8 Infrastructure commissioned after 2017 ...................................................................................................67

3.9 Forecast capacity development for 2015-2024 ...................................................................................69

3.10 Meeting of demand for gas in France in 2024 ....................................................................................70

ANNExES annexe 1 Interconnection points: subscription and utilisation rates .........................................72

annexe 2 Determination of the network’s commercial capacity ...................................................74

annexe 3 Execution of major projects .................................................................................................................76

Glossary ...............................................................................................................................................................................................78

Flap 1 Map of the GRTgaz network in 2015

Flap 2 Map of the GRTgaz network in 2024

North PEG

Trading Region South

TIGF

Dunkirk

Taisnières

Obergailbach

Oltingue

Jura

Fos CavaouFos Tonkin

Montoir-de-Bretagne

570

620

223

410

37037

H 640B 230

165225

Direction of �ow of natural gasFirm capacity in GWh/d

3 LNG terminals1 LNG terminal under constructionNetwork interconnection points

Balancing zone

National networkRegional network

1 compression station under construction

14 underground storage facilities27 compression stations

mAp OF THE GRTgaz NETwORk IN 2015

North PEG


TIGF

Dunkirk

Taisnières

Obergailbach

Oltingue

Jura


Montoir-de-Bretagne

570

620

223

410

37037

H 640B 230

165225

Direction of �ow of natural gasFirm capacity in GWh/d

3 LNG terminals1 LNG terminal under constructionNetwork interconnection points

Balancing zone

National networkRegional network

1 compression station under construction

14 underground storage facilities27 compression stations

key figures for 201432,153 km of high-pressure pipelines

583 TWh transported

energy i.e. 51 billion cubic metres of which:

• 392 TWh consumed

• 78 TWh stored

• 113 TWh transiting

640 TWh traded at the PEGs

129 shippers

802 connected customers

including:

• 17 distribution system operators

• 12 power generation plants

• 773 industrial consumers

Staff of 2,965

Investments of €663 M

Turnover of €2.05 billion

_ 1

PROFILE

GRTgaz is the operator of the high-pressure natu-ral gas transmission network over most of France. It helps to ensure efficient operation of the natural gas system bringing gas to consumers:

• the industrial facilities directly connected to the transmission network, including gas-fired power plants;

• the households, communities and enter-prises connected to the public distribution net-works that in turn are supplied by the transmis-sion network.

The GRTgaz network is a major network at the heart of Europe. Connected to the Norwegian, Bel-gian, and German networks, the Italian network via Switzerland and the Spanish network via TIGF, as well as LNG terminals on the Atlantic and Mediter-ranean coasts that can be supplied with gas from

all over the world, it provides access to diversified sources and facilitates gas trading across Europe.

GRTgaz thus contributes to enhancing energy se-curity for France and the rest of Europe, and to the completion of an integrated, efficient and competitive natural gas market.

France and Europe have undertaken an energy transition that will have to combine security of supply, competitiveness and sustainability. The gas infrastructures, and in particular the transmission networks, have a key role to play in meeting these challenges and dealing with the development of sustainable energy systems.

The aim of GRTgaz is to place its network, its of-fers and its skills at the service of energy solutions of the future in France, in Europe and worldwide.

GRTgazworking for a secure and competitive energy supply and forward-looking energy solution

2 _

FRAMEWORK FOR THE GRTgaz’S TEN YEAR NETWORK DEVELOPMENT PLAN

The Energy Code transposes into French law the European directive setting out the access con-ditions to the gas infrastructures and the common rules applicable to the national natural gas market. Within this framework, each year GRTgaz draws up a ten-year development plan for its gas transmission network in France (1) and submits it to the Energy Regulation Commission (CRE) for examination.

The ten-year GRTgaz plan lies within the frame-work of the European and French energy policies. It integrates the obligations placed on transmis-sion operators regarding security of supply. It takes into account the expectations and projects of stakeholders at national, regional and Europe-an levels. It is based on existing gas supply and demand as well as reasonable forecasts as to medium-term development of gas infrastructures, consumption and international trading.

• It identifies the main gas transmission infrastruc-tures to be built or enhanced over the next ten years.

• It lists the investments confirmed or to be made over the next three years.

• It sets out a provisional planning for all the in-vestments mentioned, making a distinction be-tween projects that have been confirmed and those that have not.

The analysis and the projects set out in this document concern mainly the national net-work. The transmission network is indeed divided up into two units:

• the national network links the intercon-nection points with the adjacent transmission networks, natural gas terminals and storage facilities. It consists of pipes with diameters of 600 mm to 1,200 mm, and it features a meshed part in which the gas can flow in both directions: the core network. The investments made on the core network provide potential benefits for all the entry and exit points in the balancing zone concerned (2);

• the regional network carries gas from the na-tional network to the distribution networks and the major industrial consumers, and also to gas-fired power plants. It consists of pipes whose di-ameter is generally less than 600 mm, and other than in specific cases, the gas can only flow in one direction.

1. European directive No. 2009/73/CE and order No. 2011-504 dated 9 May 2011 transposing the directive into French law.

2. In France, a shipper can request transmission of his gas from any entry point to any exit point in a given market zone, within the limits of the capacity subscribed at the various points. His only obligation is that of balancing incoming and outgoing quantities over the gas supply day. In 2014, GRTgaz had two balancing zones: the North zone and the South zone.

fRamewoRk foR The GRTgaz’s Ten yeaR neTwoRk developmenT plan

_ 3

FRAMEWORK FOR THE GRTgaz’S TEN YEAR NETWORK DEVELOPMENT PLAN

3. The Gas Regional Initiative, implemented in 2006 as an intermediate step in the transition from national electricity and gas markets to a single internal energy market. France participates in two of the three regions defined for gas.4. The European Network of Transmission System Operators for Gas, the association of European gas TSOs.5. Bertrand Lombard: [email protected]. Deliberation of the Energy Regulation Commission dated 17 December 2014 covering examination of the ten-year network development plan and approving the GRTgaz investment programme for 2015.

Identification of new projects or new re-quirements relies on an extensive consulta-tion process: the “Gas Consultation” in France, the North-West and South regional gas initiatives (GRI (3)) at a regional level, the work executed un-der the aegis of the ENTSOG (4) to draw up the re-gional investment plans (GRIPs) and the Ten Year Network Development Plan (TYNDP) covering the European gas network, of which the fourth edi-tion was published in March 2015, together with bilateral discussions with adjacent system opera-tors or project promoters.

The CRE collects market opinions, checks that the investment needs are actually covered, and makes sure of the coherence of the national plan with the European ten-year network develop-ment plan (TYNDP). It checks execution of the investments covering the first three years, which are binding.

Within GRTgaz, the compliance manager (5) checks the correct implementation of the plan. Subject to the competencies assigned specifically to the CRE, his mission, set out by the Energy Code, consists of ensuring that the GRTgaz practices comply with

its obligations as an independent transmission network operator (ITO).

The 2015-2024 development plan takes into account the results of the public consultation made by the CRE in November 2014 and the CRE deliberation dated 17 December 2014 (6). It has been examined jointly in coordination with TIGF. It integrates the elements included in ENTSOG TYNDP together with the elements contributed by the adjacent operators.

In this respect, it is useful to point out that a con-siderable proportion of the structures to be built or enhanced is conditioned by the projects of oth-er operators whose investment decisions have not yet been taken. For projects awaiting a decision as to execution, the financial elements presented are based on estimations and are provided for infor-mation purposes only.

Taking into account uncertainty related to mar-ket and project development in an ever evolving energy context, this document is not binding on GRTgaz beyond its legal obligations regarding execution of the developments envisaged.

4 _

FOREWORD

In many ways, the 2014 economic and gas situation in France re-

flected that of 2013: consumption fell slightly and low LNG supply required large North-South flows towards the country’s South Zone as well as the Iberian Peninsula.

Meanwhile, GRTgaz has pursued its efforts, through greater cooperation with adjacent gas infra-

structure operators, to optimise the use of its network. Consequently, at the beginning of 2015, a single Title

Transfer Point in the south of France common to the GRTgaz and TIGF Balancing Zones was com-missioned. This contractual streamlining, which aims to make the market in the south more flexi-ble, was based on the concept of a Trading Region, a first in Europe. Furthermore, access to the GRT-gaz South Zone, which had already been improved thanks to cooperation with Storengy (JTS), was further enhanced by a mechanism that uses Elengy’s LNG terminals’ storage capacity (‘circulating gas’) and by new commercial capacity offered at the entry point of the South Zone from Switzerland.

Following cost-benefit analysis widely shared with market players, GRTgaz also launched projects to strengthen the network between the north and the south of France, involving the extensive participa-tion of all public authorities. In 2018, France will thereby benefit from a robust gas transmission net-work that is able to offer French consumers a more secure and competitive supply.

After 2020, potential development of GRTgaz network primarily aim to further incorporate south-western markets into central European mar-kets and to offer the latter a better access to LNG from the Atlantic and Mediterranean basin. Most of these projects require a substantial increase in transmission capacity within France and, therefore, major investments in the GRTgaz network. The de-cision on whether or not to develop this new infra-structure will have to be based on the sustainability of demand and alternative terrestrial or maritime supply solutions. In the light of these factors, most of the adjacent gas infrastructure project promoters have postponed their projects in comparison of last year’s plan. Only capacity developments requiring

little investment and that are useful and sustainable over the long term, such as the creation of entry capacity at Oltingue, currently have the support of market players.

However, the biggest development over the past few months in France is, undoubtedly, the Law on energy transition for green growth (LTECV), which is the outcome of broad consultations with the various stakeholders. This law, which is consistent with European guidelines revised a few months ear-lier, aims to drastically reduce the volume of fossil fuels and greenhouse gas emissions; it defines goals unfavourable to natural gas. Nevertheless, certain provisions mean that natural gas, a stora-ble source of energy that is also the least polluting fossil fuel, could play a positive role in the area of mobility, the production of electricity due to the in-termittent nature of renewables and caps on elec-tricity production from nuclear sources. The emer-gence of renewable gas enhances the appeal of gas in the light of this outlook. More generally, gas infrastructure and, in particular, the gas transmis-sion network constitute a powerful asset that could benefit the energy transition process. Nevertheless, the place of gas in the energy mix still remains relatively uncertain. So that the gas industry can fully contribute to the development of French energy mix, some orientations that are favourable to gas will have to be confirmed and reflected in all future laws and regulations, particularly the Multi-annual energy programme and new Thermal regulations, which are currently being drafted.

Transmission networks have confirmed their central role with regards to facilitating the energy transition process (solidarity of regions, synergies between energy sources) and to strengthening market integration (access to the most competitive and secure energy). The development of the networks, which are very capital intensive, can only be considered in response to a sustained requirement shared by all market players and within a stable regulatory framework.

This tenth GRTgaz Ten-year network development plan aims to contribute to discussion by providing an insight into the transmission infrastructure pro-jects that may be envisaged over the next ten years and the challenges to which they respond.

I hope you enjoy reading it.

THIERRY TROUVÉ, MANAGING DIRECTOR

_ 5

SUMMARY

With over 2 billion euros invested over the 2013-2015 period,

GRTgaz has continued to execute its development programme to

increase its interconnection capacities with the adjacent networks,

facilitate access to the gas market, and ensure its efficient operation.

The forthcoming implementation of the core network

reinforcement in the north of France and the link with Belgium

will enable gas importation via the fourth French liquefied natural

gas terminal in Dunkirk, in late 2015 or early 2016.

The existing network has also shown its robustness regarding gas

transmission, even during very cold spells, while freeing up the

capacities necessary to enable shippers to take advantage of the

most competitive sources.

Because of its geographical situation, France occupies a key

strategic position in Europe, and these investments make efficient

contributions to security of supply and integration of the European

gas markets.

The GRTgaz investment programme ties in well with these

prospects. By 2018, the simplification of the market organisation

in France will lead to creation of an open, competitive single

wholesale market.

summaRy

6 _

SUMMARY

Gas: a cRedible soluTion foR eneRGy consumpTion wiTh a small caRbon fooTpRinT

Since 2010, natural gas consumption has slackened off in Europe as a whole, and also in France, under the combined effects of the economic slowdown, competition from coal for generation of electricity, and the progress made in energy efficiency. In 2014, consumption was especially affected by the exceptionally mild climate, with a fall of 16% in France and 11% in Europe as a whole.

In Europe, the Energy Union launched in 2015 is aimed at establishing a sustainable energy sys-tem that is able to reconcile security of supply and prevention of global warming with economic competitiveness by giving priority to research and innovation.

The European Union has set itself the objective of reducing its greenhouse gas emissions by 40% in 2030 as compared with 1990. France, for its part, has entered into similar undertakings by aiming at a 30% reduction in is fossil fuel consumption as compared with the 2012 reference level, with adoption of the Law governing Energy Transition for Green Growth (LTECV) in July 2015.

In this context, natural gas has the advantage of being among the energy sources that emit the lowest levels of CO2. Abundant, competitive and easy to store, it is in a strong position as regards energy transitions. Development of renewable energy sources (wind power and photovoltaic systems) can be enhanced by careful management of their intermittency; the share of nuclear power could be reduced from 75% to 50% by 2025. These two factors could encourage use of gas

for electricity generation, instead of oil- or coal-fired plants, which emit higher levels of pollution. Development of natural gas in the fields of transport or heating could also help reduce peak demand of electricity requirements and set up an energy mix with a small carbon footprint. Lastly, local production of renewable gas, such as biomethane via methanisation or synthetic methane via Power to Gas, will enable cuts in importation requirements, and hence reduce French energy dependence, while setting up an intelligent bridge between electricity and gas. These evolutions give the transmission network a key role in the French energy system to facilitate solidarity between territories.

Whatever the choices made, gas and its infrastructures have a major role to play in the future energy mix. The forecasts as to evolution in demand for gas vary widely over the period covered by the plan, depending on the hypotheses adopted concerning the various development factors. The graphs below show the different scenarios explored by GRTgaz: the reference scenario, which entails falls of about 0.7% per year, and two contrasting alternative scenarios, “Less 30” and “Diversified Uses”. These scenarios illustrate the uncertainties surrounding the long-term levels of gas demand, even though gas remains an essential part of the energy mix in all cases. The Pluriannual Energy Programming system is likely to shed fresh light on the question. To make its contribution to the ongoing discussions, GRTgaz has gone over the hypotheses underpinning these different scenarios in great detail.

_ 7

SUMMARY

new TRansmission infRasTRucTuRes in euRope

In spite of the potential erosion in gas consump-tion in Europe, the falls in production in the North Sea are likely to entail increased importation re-quirements by 2035. As things stand, only Rus-sia and the world LNG market would seem big enough to meet these new requirements. It will be necessary to open up new importation chan-nels - doubling the Nord Stream is a solution that is being examined this year, for example - and adapt the core European network to absorb the new flow configurations that the fall in produc-tion will entail.

The role of gas in the energy transition constitutes another potential factor of change in uses of gas networks. The flows will have to adapt to diffuse local production of biomethane, while providing solidarity among the territories. Depending on the constraints and ambitions involved, development

of gas-fired electricity production could entail an even more flexible, reactive network to meet the peak generation requirements.

Over the longer term, development of the infra-structures underpins the European energy policy priorities: reaching full integration of the Euro-pean market, security of supplies, competitive-ness and sustainability. The latest edition of the Network Development Plan (TYNDP 2015-2035) drawn up by the ENTSOG shows that apart from the most outlying regions (Baltic, south-east and Iberian peninsula), the market integration has already seen considerable progress. The trend is confirmed by the convergence of market prices in north-west Europe. The future developments will be aimed at reducing isolation and reaching a high level of flexibility within the European net-work to ensure enhanced market integration. The

700

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500

400

300

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100

0

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

GRTgaz-2015 scenario (with development of gas mobility)

Less 30 scenario (LTE) Diversi�ed Uses scenario GRTgaz-2015 scenario (reference)AMS2 - DGEC scenario

TOTAL CONSUMPTION (TWh)

8 _

SUMMARY

European Union is encouraging their implemen-tation by setting aside 5 billion euros for devel-opment of energy infrastructures between 2014 and 2020, and drawing up a list of the Projects

of Common Interest that can claim European backing. The GRTgaz projects, several of which are on that list, contribute to reinforcing the North-South corridor in the west of Europe.

The GRTgaz developmenT pRojecTs

2015 is seeing completion of the facilities neces-sary to link up the new natural gas terminal in Dunkirk. The terminal is to be put into service in late 2015 or early 2016, and it will provide an annual capacity of 13 bcm for the French and Belgian markets. The work to connect the termi-nal involved major reinforcement of the network towards the east, with doubling of the Hauts de France pipeline over 174 km, extended by the Arc de Dierrey, a new gas pipeline 308 km in length between Cuvilly and Dierrey, the last part of which is to be put into service in 2016.

A new exit capacity is also to be created in late 2015 at Alveringem, with commissioning of the Flanders pipeline, which will carry up to 8 bcm of non-odorised gas per year to Belgium.

A new entry capacity will then be created from Switzerland and Italy to Oltingue in 2018 to con-nect the French and Italian markets and reinforce the flows from south to north.

The market organisation in France is being simpli-fied at the same time. An initial stage was reached in April 2015 by setting up the TRS, a common market area in southern France, made up of the TIGF and GRTgaz South areas. The process will be

completed in 2018 with commissioning of the fa-cilities forming part of the Val de Saône and Gas-cogne-Midi programmes. These facilities will avoid congestion on the North-South link, thus enabling creation of a single market area for France.

New interconnections with Spain and Germany are envisaged for 2021/2022, to further strengthen the North-South corridor for the west of Europe. The projects to increase the regasification capacities at Fos and Montoir, together with development of the underground storage facilities at Manosque, could also entail network reinforcements.

Lastly, towards the end of the period covered by the plan, GRTgaz is preparing to adapt its net-work in order to ensure transmission continuity for customers currently supplied with “L-gas” (a low calorific value gas) from the Groningen field in the Netherlands, which is nearing the end of its commercial service life.

As things stand, a joint analysis with TIGF ena-bles us to ensure that the peak requirements can be met up to the end of the period covered by the plan under all the demand scenarios, taking into account the forecast entry capacities for the French transmission network.

_ 9

SUMMARY

DEVELOPMENT OF FIRM ENTRY AND EXIT CAPACITY

Entry capacityGWh per day 2015 (1) Confirmed Envisaged (2) 2024 (3)

Norway (Gasco) 570 - - 570

Germany 620 - - 620

Belgium (H gas (4)) 640- -

640

Belgium (B gas (5)) 230 230

Spain (via the TIGF network) 225 - 230 225 - 455

Switzerland / Italy 0 100 - 100

LNG terminals in the North zone 370 520 450 620 - 1,340

LNG terminals in the South zone 410 - 327 410 - 737

Total 3,065 350 1,007 3,415 - 4,692

Exit capacityGWh per day 2015 Confirmed Envisaged 2023

Belgium - 270 - 270

Germany - - 100 100

Switzerland / Italy 260 - - 260

Spain (via the TIGF network) 165 - 80 165 - 245

Total 425 270 180 695 - 875

1. Creation of a TIGF-GRTgaz Sud trading region on 1/4/20152. Subject to network reinforcement.3. The merger of the zones in 2018 could entail further evaluation of capacity.4. H gas: Gas with a High Calorific Value, usually containing over 90% of methane.5. L gas: Gas with a Low Calorific Value, from the Netherlands, and distributed in the north of France. This gas can be distinguished by its higher nitrogen content.

10 _

The mild weather in 2014 amplified the decrease of European gas consumption. It had already slackened since 2011, due to the economic slowdown and strong competi-tion from coal and renewable energy sources for electricity generation.

Industrial competitiveness is also affected by gas prices in Europe, which are three times higher than in the USA. The dynamic Asian markets have continued to attract world-wide LNG supply in 2014: LNG deliveries in Europe have been halved since 2011.

However, the fall in oil prices since August 2014 could well change things. LNG prices have fallen in Asia, following notably the restart of nuclear power plants in Japan and the commissioning of new liquefaction facilities. Thus LNG is arriving in Europe again, leading to lower prices in the South of France and the Iberian Peninsula, a region characterised by its reliance on LNG.

In a context in which reduction of green-house gas emissions constitutes a priority, evolution of gas demand remain uncertain over the medium term. Nevertheless, Europe will certainly have to increase its importats to make up for the declining production in the North Sea and the Netherlands. New infra-structures will be necessary to secure the im-portation routes, diversify the supply sources and distribute the new flows in Europe.

The launch of the Energy Union should meet these challenges, articulating its action around five themes: security of supply, inte-gration of the internal energy market, energy efficiency, reduction of CO2 emissions, and research and innovation. In particular, the European Union is to set aside 5.3 billion euros for the construction of energy infra-structures between 2014 and 2020. A new list of Projects of Common Interest will thus be drawn up by the end of 2015.

EVOLUTION AND PROSPECTSFOR THE GAS MARKET IN EUROPE

1

1.1

A new drop in European consumption in 2014

1.2

World prices again contrasted in 2014

1.3

Stabilisation of supplies

1.4

Uncertainty over long-term demand

1.5

The European energy policy and its objectives

1.6

Development of gas infrastructures in Europe

1.7

Major European infrastructure projects

_ 11

EVOLUTION AND PROSPECTS FOR THE GAS MARKET IN EUROPE

The European Union represents about 12% of worldwide energy consumption. It also accounts for 12% of worldwide natural gas consumption, contributing to a quarter of its primary energy use. In 2014, the consumption of the 28 countries in the European Union fell by 11% to 409 bcm, (not corrected for the climate, source Euro gas), due to the effects of exceptionally mild weather. 2014 was indeed the warmest year on record in France, in Europe and worldwide. Consumption had already fallen by 10% in 2011, another year showing record warmth. The drop was especially marked in France, where gas is mainly used for heating.

Consumption of natural gas also fell due to the effects of the economic slowdown on industrial demand, gains in energy efficiency and competi-

tion from coal and renewable energy sources for

electricity generation.

GAS CONSUMPTION IN 2014*

In bcm 2013 2014 Evolution

Germany 87.2 76.2 -13%

United Kingdom 78.7 71.5 -9%

Italy 68.7 60.7 -12%

France 46.1 38.6 -16%

Netherlands 39.9 34.8 -13%

Spain 30.9 27.9 -10%

Total EU 28 460.7 409.1 -11%

* Before climatic correction Eurogas 2015.

1.1 a new drop in european consumption in 2014

European Union (28 countries)

United Kingdom

Austria

Italy

Spain

Germany

Netherlands

Poland

France

ENERGY MIX IN EUROPE

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Coal Oil Gas Nuclear Renewable energy sources

Source Eurostat 2013

12 _


GLOBAL GAS CONSUMPTION (BCM)

2012 20142010 2011 2013

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100

0North America South and Central America Europe other Middle East Asia Paci�c AfricaEU 28

bcm

CHANGE IN ENERGY PRICES ON A BASIS OF 100 (JANUARY 2010)

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100

50

0

Jan. 2

010

Apr. 2

010

July 2

010

Oct. 20

10Jan

. 201

1Ap

r. 201

1Jul

y 201

1Oct.

2011

Jan. 2

012

Apr. 2

012

July 2

012

Oct. 20

12Jan

. 201

3Ap

r. 201

3Jul

y 201

3Oct.

2013

Jan. 2

014

Apr. 2

014

July 2

014

Oct. 20

14Jan

. 201

5Ap

r. 201

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y 201

5Oct.

2015

Brent Average price of imported coal in Europe NBP gas

Elsewhere in the world, gas demand remains dy-namic, but it shows signs of slackening. In the USA, it is buoyed up by development of shale gas, which is replacing coal. In Asia, growth in demand is slowing down, with an increase of just 2% in 2014 as compared with 2013, after several years with annual growth of over 5%.

The crude oil market is showing the same signs of slowing down, whereas the production offer remains abundant. The price per barrel of crude

oil has been halved since August 2014, falling

from $110 to $60 per barrel, and staying below

the symbolic level of $100 on average for 2014.

The prices of the other energy sources followed

those of crude oil, also showing falls. The drop

in oil prices was reflected, with an offset of a few

months, in the prices of natural gas and LNG,

which are still often indexed on sliding averages

of oil product prices.

BP Statistical review 2015

GRTgaz based on electronic stock exchanges

_ 13


In recent years, the growth in production of shale gas in the USA, the biggest gas producer in the world in 2014 (7), the drop in consumption in Eu-rope and the strong demand for gas in Asia have led to major price differences between continents. The situation remained unchanged in 2014. The spot prices in the USA remained below $4/MMBtu

in 2014, three times lower than in Europe. LNG prices in Asia in 2014 stayed at $16/MMBtu, thus attracting most of the worldwide LNG production.

However, the first half of 2015 points to fresh changes. The drop in crude oil prices triggered a slump in Asian LNG prices in December 2014, to between $6 and $8/MMbtu. The fall in Asian de-

1.2 world prices again contrasted in 2014

CHANGE IN WHOLESALE GAS PRICES ON THE WORLD'S MAIN MARKETS

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2

01996 1998 2000 2002 2004 2006 2008 2010 2012 2014

LNG Japan cif Average German import price UK Heren NBP US Henry Hub

USD/MBtu


CHANGE IN LONG-TERM CONTRACT AND SPOT PRICES IN EUROPE

PEG North DA PEG South/TRS DA TTF DA ZTP DA NCG DA PSV DA PMI German

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40€/MWh

Jan. 2

013

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2013

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013

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013

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y 201

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g. 20

13Se

pt. 20

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2013

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013

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2013

Jan. 2

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2014

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Apr. 2

014

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e 201

4

Jan. 2

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Feb.

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March 2

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015

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e 201

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2014

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14Nov

. 201

4De

c. 20

14

GRTgaz based on electronic stock exchanges and BAFA (average price of importations in Germany, representative of long-term contracts)

7. BP Statistical review of world energy 2014.

14 _


PEG SOUTH (TRS) / PEG NORTH PRICE DIFFERENTIAL

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Jan.

2011

Apr. 2

011

July

2011

Oct.

2011

Jan.

2012

Apr. 2

012

July

2012

Oct.

2012

Jan.

2013

Apr. 2

013

July

2013

Oct.

2013

Jan.

2014

Apr. 2

014

July

2014

Oct.

2014

Jan.

2015

Apr. 2

015

€/MWh

mand (restarting of the nuclear power plants in Japan, slowing growth rates in China) and new gas liquefaction capacities in Australia are other factors keeping prices low.

In Europe, the spread between spot market prices and long-term contract prices is decreasing. Northwestern marketplaces are tending towards homogeneity, apart from the markets in south-west Europe, PSV in Italy and PEG Sud/TRS.

PEG Sud (or Trading Region South since 1 April 2015) saw high overall prices from 2012 to 2014. Due to the fall of LNG deliveries in Europe, in particular at Fos and in Spain, the pipeline- transmitted gas flows towards the South of France showed sharp increases, saturating the North-South link in France. The price spreads between GRTgaz’s North and South zones, which stood at

zero in 2011, rose to €1.6/MWh on average in 2012, and €3.5€/MWh in 2014.

the trading region south

The TRS (Trading Region South), the market area common to TIGF and GRTgaz in the South of France, was launched on 1 April 2015. The TRS was set up with the aim of enhancing the attractiveness of the French market, by increasing the liquidity and depth of the southern market. Designed within the framework of the European target outlines, this model of market area integration is a first for Europe.

In this single market, the gas flows from customers enter and leave via any physical point of the GRTgaz and TIGF networks. Any imbalance between shippers in the Trading Region South are spread between the two GRTgaz Sud and TIGF balancing zones, which continue to exist in the same way as before implementation of the TRS.

With the TRS, shippers thus benefit from a simplified system that avoids having to

subscribe capacities at the interconnections between the two networks. They no longer have to declare, each day, the quantities that they want to transmit via these capacities.

The two French transmission network operators (GRTs) cooperated closely to develop the operating modalities for the joint trad-ing point:• GRTgaz deals with transactions for the

whole of the new market area and eval-uates the physical flows transmitted be-tween the GRTgaz and TIGF networks;

• TIGF is in charge of calculating the shipper imbalances in the mesh of the two GRTs’ balancing zones.

The principles of the TRS model were vali-dated by the CRE deliberation dated 22 May 2014 “covering the operating rules for the market area common to the GRTgaz Sud and TIGF zones as from 1 April 2015”.

_ 15


TOTAL TRADED VOLUMES ON CONTINENTAL HUBS VERSUS NBP

0

500

1 000

1 500

2 000

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

United Kingdom (NBP)

Continental (estimated)

Netherlands (TTF)

Germany (NCG and GASPOOL)

Italy (PSV)

Netherlands (TTF) (Est. netted volumes prior nomination)

Belgium (Zeebrugge and ZTP)

France (PEG)

Austria (CEGH)

Bcm

The fall in LNG prices noted in Asia at the end of 2014 led to price drops in the Trading Region South, and to enhanced levels of availability for the North-South link.

Nonetheless, GRTgaz remains committed to main-taining the steps taken to optimise the capacity made available for shippers, where necessary, and improve gas offer in the South whenever possible.

In 2014, the TTF market moved to first place in the classification of European markets in terms of volumes traded, with the British NBP market remaining the biggest physical market. According to an ACER study published early in 2015, only the British hub reaches the objectives of the Gas Target Model, with the TTF as the other market coming closest to them.

MS-ATR

TRS

NBP

TTF

Gaspool

CEGH

NCG

PSV

ZTP

ZEE

PEG North

THE MAIN GAS TRADING POINTS IN EUROPE

IHS Energy, national sources

16 _


Russia, the biggest supplier for Europe in 2014Production in the European Union fell by 10% in 2014, mainly due to the limitation in the produc-tion capacity of the Groningen field in the Nether- lands. The European Union’s production none-theless remains the main source of natural gas in 2014, providing 34% of its supply.

The mild weather has quite logically led to major reductions in the volumes imported, in particular from Russia. However, Russia is still the biggest supplier of gas to the European Union, providing 31% of supply, followed by Norway (26%) and Algeria (8%).

LNG deliveries to Europe remained stable in 2014 as compared with 2013, after two consecutive years of decline. They were halved between 2011 and 2013, falling from 85 to 45 bcm, with 40 bcm rerouted to Asia. LNG now accounts for just 11% of European supply, with Qatar as the

main supplier. The fall in LNG prices in Asia late in 2014 led to a renewed surge of LNG deliveries to Europe, with a 21% increase in deliveries during the first half of 2015 as compared with the first half of 2014.

GAS SUPPLIES FOR EUROPE

In bcm 2013 2014

EU production 147 132

Russia 136 121

Norway 105 103

Algeria 35 30

Qatar 23 23

Nigeria 7 4

Others 13 11

Total 469 424


1.3 stabilisation of supplies

EU production132

Qatar 23

Algeria 11

Other (Trinidadand Tobago, Peru,

Norway) 7

Nigeria 4

Norway 101

Algeria20

Libya6

Russia 121

Supplies via gas pipelines

LNG supplies

LNG terminals

LNG terminals under construction

GAS SUPPLIES FOR EUROPE IN 2014 (IN BCM)


_ 17


Full storage facilitiesStored natural gas plays an essential part in ensuring the security and flexibility of the European network, in particular to deal with peak consump-tion in the winter. However, the reduced price spreads between summer and winter on the spot markets in recent years have had a negative effect on the storage levels. On the contrary, the fears caused by the Ukraine crisis, together with the ex-ceptionally mild weather, led to the replenishment of storage facilities in 2014. The fall in crude oil prices late in 2014 led to reductions in gas storage levels during the 2014/2015 winter to fill them up with cheaper gas during the summer of 2015.

In the light of the decreasing European production, changes in weather patterns and geopolitical ten-sions such as those between Russia and Ukraine, suitable use of the storage capacity is one of the crucial questions discussed when drawing up the European Strategy for the Security of Energy Supply.

SPAIN

UNITED KINGDOM

IRELAND

DENMARK

SWEDEN

ESTONIA

LATVIA

LITHUANIA

POLAND

SLOVAKIA

CZECH REPUBLIC

HUNGARYAUSTRIA

GERMANY

NETHERLANDS

BELGIUM

LUX.

SLOVENIAROMANIA

UKRAINE

BULGARIA

TURKEYGREECE

ITALY

PORTUGAL

52

12

12

32

25

13

12

17

15

4

22

62

4

3

3

86

9

5

LNG terminals

EU 28 total

LNG terminals under construction

Annual regasi�cation capacity in bcm/country

Annual storage capacity in bcm/country

195 108

STORAGE AND REGASIFICATION CAPACITIES IN EUROPE IN 2014 (IN BCM)

Gie 2015

REPLENISHMENT LEVELS OF EUROPEAN STORAGE FACILITIES (EU 28)

2011 2012 2013 2014 2015

0

10

20

30

40

50

60

70

80

90

Jan.

2010

Fev.

2010

Mar

ch 2

010

Apr. 2

010

May

201

0Ju

ne 2

010

July

2010

Aug.

2010

Sept

. 201

0Oc

t. 20

10No

v. 20

10De

c. 20

10

bcm

GSE 2015

18 _


In its World Energy Outlook 2014, the IEA con-firmed its forecasts concerning a relatively small increase in demand for natural gas in Europe, while revising it further downwards as compared with its own forecasts in 2013. Gas consumption has slumped since 2010 due to slower economic growth and competition from coal and renew-able energy sources for electricity generation. It is unlikely to return to its historic levels before 2030-2035.

However, European consumption could rise as from 2020 under the effects of stricter regulations covering emissions of CO2 and other pollutants, which are likely to hamper use of coal for electricity generation and encourage use of gas as a fuel for public transport systems.

According to Eurogas, gas could account for 24% to 30% of European primary energy con-sumption in 2035, with the share of natural gas in electricity generation representing the main factor of uncertainty.

1.4 uncertainty over long-term demand

EU GAS CONSUMPTION FORECASTS IN BCM

bcm/year

400

450

500

550

600

650

2010 2012 2020 2025 2030

AIE 2012 AIE 2013 AIE 2014 - new policies

AIE - World Energy Outlook 2012, 2013, 2014

_ 19


Over the medium and long term: an acceleration in the importation requirements?According to the IEA, the fall in conventional gas production in Europe, and in particular in the Uni-ted Kingdom and the Netherlands, will lead to a rise in imports, which could reach about 100 bcm by 2030, i.e. more than twice the consumption in France. Imports, which represented 69% of Euro-pean supply in 2014, could reach 80% in 2035.

These new importation requirements could see acceleration. In the Netherlands, following earth-quakes in the Groningen region, the Dutch govern-ment announced on 23 June 2015 that production from the field, the largest natural gas deposit in Western Europe, would be limited to 33 bcm for the gas year 2015/2016, as against a maximum production of 425 bcm over the 2006-2015 pe-riod. Further decisions are expected late in 2015.

Moreover, according to the Norwegian authorities, exports of Norwegian gas to Europe are likely to fall as from 2020, and be reduced from 115 bcm/year to 50 bcm/year by about 2030, un-less fresh fields are found and exploited, mainly in the Arctic region.

This means that Europe, and the north-west in particular, will have to rely on new gas imports, with Russian gas and LNG the most likely sources.

The first signs of a return of LNG in Europe were noted in 2015. The trend could well be confirmed with commissioning of new liquefaction capaci-ties in Australia and on the eastern coast of the USA (160 bcm of annual capacity between 2015 and 2018), whereas worldwide demand for LNG is unlikely to exceed +3% per year, due to the slowdown in growth in Asia, the restart of nuclear power plants in Japan and the disappearance of LNG demand in the USA.

EVOLUTION OF THE CONVENTIONAL GAS PRODUCTION IN EUROPE

160

140

120

100

80

60

40

20

0

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

NL UK DE IT Others

bcm/year

TYNDP 2015

20 _


Energy is one of the priorities set by the new Euro-pean Commission appointed following the Euro-pean parliament elections in May 2014.

Its new president set out to create a collegial or-ganisation. Energy is thus the prerogative of two members of the Commission:

• the Vice-president for Energy Union;

• the Commissioner for Climate Action and Energy.

Indeed, the European Union is faced with a double challenge: reaching the objectives that it set itself regarding reductions in CO2 emissions on the one hand, and maintaining the security of supplies in spite of the unrest in Ukraine and the Middle East on the other hand. This has to be done in a difficult economic context in which the European industrial concerns are losing competitiveness as compared with their American counterparts, who are able to make the most of competitive energy costs as a result of the shale gas revolution.

The Member States have adopted a framework of action regarding energy and the climate over the 2020-2030 period, in which they have set strict objectives at the scale of the European Union: re-ducing greenhouse gas emissions by 40% as com-pared with 1990 before 2030, and increasing to 27% the share of renewable energy sources in the final energy consumption (8).

This is the ambition that the European Union will present at the 21st Conference of parties at the 2015 United Nations Framework Convention on Climate Change in Paris (COP21).

Furthermore, the uncertainties raised by the Rus-sia-Ukraine crisis led the Commission to propose on 28 May 2014 a new European Strategy for the Security of Energy supply (ESSES). Indeed, five EU countries (Finland, Slovakia, Bulgaria, Estonia and Lithuania) are 100% dependent on Russia for their gas imports, and the level stands at 39%

for Europe as a whole. Amongst other things, this reflection is to lead to revision of regulation 994/2010 governing security of supply.

These two priorities, lowering CO2 emissions and security of supply, form the basis of the working programme adopted by the Commission for energy. The programme could be summed up by the communication published on 25 February 2015 COM(2015)80 entitled “A Framework Stra- tegy for a Resilient Energy Union with a forward- Looking Climate Change Policy”. It sets out the European strategy along five avenues:

• Energy security, solidarity and trustThe Commission is determined to enhance diver-sification of natural gas supply (sources, suppliers and routes), relying mainly on central Asia and the Mediterranean (e.g. Algeria). The future European fund for strategic investments could thus well be called on.

The Commission will also rely on the future strategy for LNG and storage, which was the object of a public consultation during the summer of 2015.

Lastly, the revision regulation 994/2010 on se-curity of supply is likely to highlight cooperation

1.5 the european energy policy and its objectives

8. 2030 climate and energy framework, European Commission, January 2014.

objectives for 2030

27%: share of renewable energy sources

27%: energy savings

40%: reduction in greenhouse gas emissions as compared to 1990

_ 21


between Member States. The Commission’s Stress Tests indeed showed that this is a necessary condi-tion for efficient crisis management by the market and the institutions alike.

• A fully-integrated internal energy market

This is based on physical integration of the infra-structures, and also on implementation of a cer-tain number of rules governing use.

Regulation 347/2013 on Projects of Common In-terest and the corresponding funds participate in development of the infrastructures enabling each European consumer to benefit from secure sup-plies at competitive prices.

Implementation of the network codes is likely to enable efficient, transparent, non-discriminato-ry use of the infrastructures. In this respect, the ENTSOG has made major contributions to har-monisation of practices by drawing up all the network codes currently planned. The network code on harmonisation of transmission tariffs is the last one that remains to be approved, after being submitted to the ACER for the second time on 31 July 2015.

• Energy efficiency helping to moderate demand

The main efforts will be centred on the transport and building sectors, where potential savings are seen as being considerable. In particular, the Commission will put forward a strategy dedicated to heating networks. Concerning transport, the efforts must be centred on development of alter-natives to road transport (i.e. rail, waterway and maritime solutions) and to crude oil for road trans-port. Within this framework, the Commission pro-poses further measures to the Member States in the “Alternative Fuels Infrastructure” Directive.

• “Decarbonisation” of the economyThe Commission continues to make the ETS (Emis-sion Trading System) the cornerstone of its strategy to cut CO2 emissions. Europe also sets out to be-come the leader in development of renewable en-ergy sources from a technological standpoint, and also in terms of integration with the market rules.

• Research, innovation and competitiveness

The four main lines of research identified by the European Commission are: development of a new generation of renewable energy sources, intelli-gent networks, energy efficiency and transport.

Enhanced coordination between Member States and the Commission is also expected for development of the CCSR (carbon dioxide capture, storage and recovery) activities and safety in the nuclear power field.

The working programme is currently being dis-cussed and further details will be forthcoming. For natural gas, the next steps are as follows:

• the first forum on infrastructures in Copenha-gen on 9 and 10 November;

• proposal by the Commission in the first quarter of 2016 of a “gas package” including a proposal to revise regulation 994/2010 on security of supply and the European strategy for LNG and storage.

As things stand, it is not certain that these actions will provide enhanced visibility as to the long-term role for gas. The future remains uncertain for the actors in the gas industry, and this weighs on the investment decisions, for which visibility over periods of 30 to 50 years is fundamental. None-theless, the transmission infrastructures are more vital than ever for the energy security of Europe, as set out below.

22 _


Development of gas infrastructures is aimed at se-curing access to resources, putting an end to the dependency of certain Member States on a single source, widening the range of choices, and facilitating trading between the most competitive sources for the benefit of the end customers. The aim is also to enhance the flexibility of the gas system to meet the requirements of modulated use of gas.

In March 2013, the European Parliament adop-ted a regulation “concerning guidelines for trans- European energy infrastructures”. In the field of gas, four main strategic corridors for Europe are identified, including one that concerns France di-rectly: the North-South corridor for Western Europe, which is aimed at better interconnecting the Iberian peninsula and Italy with the north-west European markets. The regulation also de-fined “Projects of common interest” (PCIs) that benefit from accelerated authorisation procedures and incentive measures, and are eligible for Euro-pean Union financial backing.

The ENTSOG Network Development Plan (TYNDP)Within the framework of the implementation of the third energy package, the ENTSOG publi- shes a Ten Year Network Development Plan (TYN-DP) every two years. This information document takes into account the development plans of each Member State. It is aimed at assessing the ade-quacy of the scenarios covering supply, demand and infrastructure development in the light of the three pillars of the European energy policy (com-petitiveness, security of supply and sustainability). Now that regulation 347/2013 on the trans- European energy infrastructures has come into force, the TYNDP also constitutes the initial stage for the selection of PCI projects.

For this purpose, the European network model takes into account the balancing zones, the in-terconnections between zones, the importation capacity (including LNG) and storage facilities. The adequacy between supply and demand is

then simulated up to 2035, using several sets of hypotheses as to annual and peak demand, sup-ply and prices per source, and partial or complete execution of the infrastructure development.

The results are provided in the form of a dozen or so indicators showing various perspectives of the European energy policy pillars.

The latest edition, ENTSOG TYNDP 2015-2035, was published in March 2015. It sets out a sum-mary of the gas infrastructure projects at the Eu-ropean level, including the GRTgaz 2014-2023 Network Development Plan.

The extension of the TYNDP time frame from ten to twenty-one years has shed light on structural trends. Although the priority for 2025 is to com-plete integration of the European market, and its infrastructure component in particular, maintaining diversification of supplies can be seen as a long-term challenge, due to the fast reductions in production of conventional gas in Europe.

Finalising integration of the European infrastructuresThe modelling of the European gas system shows that apart from the most outlying regions (Baltic, south-east and Iberian Peninsula), the level of in-tegration is already high. This result is confirmed by the convergence of market prices along a wide diagonal from the NBP to the PSV. Implementation of the network codes should enable the coun-tries of Central Europe to benefit in full from the existing infrastructures.

Although the Iberian Peninsula, and to a lesser extent the south of France, remain heavily de-pendent on the LNG market, that exposure is not problematic in terms of security of supply, due to the diversification of this type of import. On the other hand, the heavy dependence of the coun-tries in the Baltic region and south-east Europe on Russian gas remains a source of concern for development of these markets and their integration in the rest of Europe.

1.6 development of gas infrastructures in europe

_ 23


In these regions, implementation of the network codes will have to be completed by suitable development of the interconnection with the Europe-an core network.

Maintaining diversification of suppliesThe integration of the European market expected over the short to medium term will constitute an asset to be maintained. It will be brought un-der pressure by the swift decline in European gas production, entailing increased levels of imports. As things stand, only Russia and the world LNG market would seem big enough to meet these new requirements, with the corresponding risk of reduced diversification of supplies. A situation of this type could threaten the competitiveness and security of gas supplies for the whole of Europe.

Without the assurance of a long-term role for gas in the European energy mix, Europe cannot be seen as a safe enough market in terms of volume to enable its connection to new production zones.

If these new imports do materialise, they will en-tail adaptation of the European core network to enable implementation of new flow outlines.

The GRTgaz infrastructure projects of a regional or European nature, set out below in this plan, meet this double challenge.

In terms of integration of the European market, the merger of the North and South zones will finalise integration of the French market. The projects involving reinforcement of the intercon-nections with the adjacent countries form part of the reinforcement of the North-South corridor for Western Europe.

A new list of Projects of Common InterestThe list of PCIs is drawn up by the European Commission every two years on the basis of proposals put forward by the Regional Initiative Groups (RIGs) and after consultation of the ACER. The European Parliament and the Council have a maximum period of 4 months to approve it or reject it completely.

The initial list of PCIs, published in October 2013, was based on a pilot methodology defined by the

European Commission. It included 9 projects con-cerning GRTgaz. They covered:

• Easter Axis Spain- France – interconnection point between Iberian Peninsula and France at Le Perthus (Midcat project);

• new interconnection between Pitgam (France) and Maldegem (Belgium);

• interconnection between France and Luxembourg;

• reverse flow interconnection between Switzer-land and France;

• reinforcement of the French network from South to North - Reverse flow from France to Germany at the Obergailbach/Medelsheim in-terconnection point;

• reinforcement of the French network from South to North on the Bourgogne pipeline be-tween Etrez and Voisines (Val de Saône project);

• reinforcement of the French network from South to North on the east Lyonnais pipeline between Saint-Avit and Etrez (Arc Lyonnais);

• reinforcement of the French network from South to North on the Arc de Dierrey pipeline between Cuvilly, Dierrey and Voisines;

• gas pipeline connecting Algeria to Italy (Sardinia) and France (Corsica) (Galsi and Cyréné pipelines).

Among these nine projects, two are under construc-tion (interconnection with Belgium and Arc de Dier- rey) and two have been confirmed for execution (Val de Saône and entry capacity with Switzerland).

Following publication of the 2015-2035 TYNDP, a list of the PCIs is currently being updated on the basis of the cost/benefit analysis methodolo-gy drawn up by the ENTSOG, and approved by the European Commission and the ACER. Cost/benefit analyses have been made for each of the projects requesting a PCI label.

GRTgaz has proposed renewal of the PCI label for all its projects, apart from those under construc-tion, and addition of the Gascogne-Midi project, in association with TIGF, and the project to con-vert the L gas network to H gas, in association with Storengy, Fluxys and GrDF.

The 2015 list of PCIs is to be published in Decem-ber 2015.

24 _


Gas pipelinesNumerous importation projects have been brought up and then cancelled in recent years. These projects are aimed mainly at securing sup-ply for Eastern Europe, avoiding the Ukrainian route or reducing the region’s dependence on Russian gas. The following projects are currently being examined:

• Nord Stream has announced doubling of its current capacities of 55 bcm/year. The two pipe-lines brought into service in 2011 and 2012 car-ry gas over 1,220 km from Russia to northern Germany via the Baltic Sea. The extra 55 bcm/year could be put into service in 2019;

• following cancellation of the South Stream pro-ject to import Russian gas via Bulgaria to Austria, late in 2014, new projects have been put for-ward, in particular Turkish Stream, with a ca-pacity of 63 bcm/year from Russia, via Turkey and the Black Sea, Eastring from Turkey to Slovakia via Bulgaria and Romania, and Tesla through Greece, Macedonia, Serbia and Hungary.

A high-level group has been set up in the region (Central and Southern Europe Gas Connectivity, CESEC) to coordinate and facilitate trans-Europe-an interconnection projects and diversify sources of supply in the region.

In this context, development of the South Corri-dor constitutes one of the priorities for the Eu-ropean Union. TAP in particular opens up access to resources in Azerbaijan, and, over the longer term, potentially from the Middle East countries via Turkey (Iraq, Iran, Turkmenistan):

• the Trans Adriatic Pipeline (TAP) will link Turkey and Italy over 800 km, via Albania and Greece, and provide a capacity of 10 bcm/year from Azerbaijan. It was confirmed in 2013, and it is expected to be brought into service in 2020;

• the Trans Anatolian Natural Gas Pipeline (TANAP) will cross Turkey further upstream, and is likely to be put into service in 2018/2019;

• GALSI would link Algeria and Italy via Sardinia, providing a capacity of 8 bcm/year, but the in-vestment decision has been postponed several times.

LNG terminalsIn all likelihood, LNG will constitute a major share of Europe’s growing import requirements. This prospect could entail investments to guarantee enhanced direct or indirect access to this resource. In this context, there are numerous projects in Eu-rope covering development of regasification and interconnection capacities to enlarge the area in which LNG could be used.

• a new natural gas terminal has been put into service in Klapeida, Lithuania (5 bcm/year);

• the Dunkirk LNG terminal under construction on the English Channel should be operational at the end of 2015 with a capacity of 13 bcm/year;

• other projects involving creation or extension of natural gas terminals are currently being ex-amined, in particular in the zones in which the gas access solutions show little diversification (Adriatic Sea, Black Sea) or on the western and southern seaboards of Europe, mainly in Bel-gium, France and Italy.

1.7 major european infrastructure projects

_ 25


SPAIN

UNITED KINGDOM

IRELAND

DENMARK

SWEDEN

ESTONIA

LATVIA

LITHUANIA

POLAND

SLOVAKIA

CZECH REPUBLIC

HUNGARYAUSTRIA

GERMANY

NETHERLANDS

BELGIUM

LUX.

SLOVENIAROMANIA

UKRAINE

BELARUS

BULGARIA

TURKEY

RUSSIA

GREECE

ITALY

PORTUGAL

Nord Stre

am

Galsi

TeslaEastring

Turkish str

eam

TANAPTAP

MAJOR GAS SUPPLY INFRASTRUCTURE PROJECTS IN EUROPE

26 _

EVOLUTION AND PROSPECTS FOR THE GAS MARKET IN FRANCE

2

2.1

Diversified supply sources

2.2

Decreasing consumptions in 2014

2.3

The role of gas in the energy transition

2.4

Gas demand forecast

2.5

Public service obligations in the event of exceptionally cold spells

2.6

The alternative scenarios for the period up to 2030

2.7

The transmission offer of GRTgaz

2.8

Demand for transmission capacity on the GRTgaz network

France is the fourth largest European gas market, with consumption of about 45 bcm (35 bcm within the GRTgaz perime-ter in 2014). It imports over 99% of the gas it consumes. Its geographical position gives it the most diversified gas supply in Europe, and trading possibilities on the East-West and North-South axes alike: these are key assets for security of energy supply at national and Eu-ropean levels.

In 2014, natural gas represented about 14% of primary energy consumption in France and 21% of final consumption (9). Over the period up to 2024, GRTgaz anticipates a stable con-sumption, with a decrease of about -0.8% per year in consumption for the residential sectors and about -0.7% per year for industry, com-pensated by an increase in gas consumption for electricity generation as from 2017-2018.

Over the longer term, the Law on Energy Tran-sition for Green Growth has set energy con-sumption levels on a downward path, and in particular carbon-based sources such as natu-ral gas. Nonetheless, development of renewa-ble energy sources for generation of electricity (wind power and photovoltaic systems) and the reduction in the share of electricity generated by nuclear plants from 75% to 50% in 2025

could encourage use of gas for power generation, in particular to deal with the intermit-tency of generation from renewable energy sources. This would involve encouraging use of gas rather than coal, which is currently chea-per but emits more carbon dioxide. Moreover, transfers from more polluting energy sources to natural gas, especially for mobility, could help to reach a low-carbon energy mix, all the more so if gas becomes renewable (biomethane, synthetic methane). Depending on the hypotheses adopted, three scenarios have been examined. The uncertainty around the evolution of gas demand is illustrated by the wide range covered by these scenario over the period covered by the plan.

The main GRTgaz network is sized mainly to meet requirements as to the flexibility neces-sary to optimise the shippers’ portfolios of sup-plies. In this respect, in 2014 the network once again showed its ability to meet increased north-south flow requirements to make up for the drop in LNG supplies to France and the Iberian Peninsula. The entry and exit capacity of the GRTgaz network are still heavily sub-scribed. Most of them are used at their maxi-mum level at least once a year, thus showing that the network is suitably sized.

_ 27


France currently imports almost all the gas it con-sumes. To ensure the security of its energy supply, it has developed an active policy to diversify its sources and routes by making the most of its ad-vantageous geography.

France is connected by gas pipelines to Norway, Belgium, Luxembourg, Germany, Italy via Switzer-land, and Spain via TIGF, so it benefits from several sources of gas in gaseous form. With LNG termi-nals on the Atlantic and Mediterranean coasts, and in the English Channel in the near future, it can receive LNG from anywhere in the world. France is the only country in Europe that has such diversified gas resources at its direct disposal, so it is ideally placed to ensure security and competi-tiveness of European gas supplies by providing ar-bitrage opportunities on the east-west and north-south axes alike.

This situation is further enhanced by powerful, well-situated gas infrastructures at the service of over 11 million customers:

• the most fully developed transmission network in Europe, 37,000 km;

• the biggest distribution network in Europe with almost 200,000 km;

• the third largest regasification capacity, 24 bcm/year;

• the third largest storage capacity, with a useful volume of over 12 bcm, i.e. 30% of national consumption, which provides a major security margin, helps to meet seasonal variations in con-sumption, and opens up trading opportunities.

In 2014, LNG supplies saw a further fall of 20%, after two consecutive years of decrease, due to the ongoing attraction of Asia. Between 2011 and 2014, the quantities of incoming LNG were

2.1 diversified supply sources

9. Source: SOeS, energy balance for France in 2014. French primary consumption adjusted for climate conditions.

FRANCE'S NATURAL GAS SUPPLY BETWEEN 2011 AND 2014

TWh

600

500

400

300

200

100

02011 2012 2013 2014

LNG Other, unspeci�ed Russia Netherlands Russia

SoeS 2014

28 _


halved, representing only 13% of imports in 2014 as against 28% in 2011. These supplies come mainly from Algeria and Qatar. Spot purchases on the Belgian, Dutch or German markets, of gas of indeterminate origin, represent one quarter of the incoming supplies. Norway remains the main supplier of natural gas with 38% of the gross

incoming quantities, followed by Russia and the Netherlands. The Norwegian and Dutch supplies constitute half of the supplies arriving in France. The prospects of falls announced for these sour-ces, and the volatility of the flows, confirm the need for infrastructures that are correctly sized, sturdy and flexible.

About 9% of the gas imported is type L gas with a low calorific value, coming mainly from the Gro-ningen field in the Netherlands. The deposit has reached an advanced stage of depletion and its exploitation is apparently causing earthquakes. Early in 2014, the Dutch government announced that the export contracts would not be renewed, and production at Groningen is currently limited to the minimum level enabling existing contracts to be met and ensuring security of supply for con-sumers of L gas. For France, extra quantity of H gas will be necessary to make up for the gradual reduction in its L gas supply as from 2024 and complete phasing out by 2029 at the latest. Ta-king into account the quantities involved and the subscription of capacity, the GRTgaz transmission network has already sufficient entry capacity for H-gas. However, GRTgaz is attentive to the mar-ket, to examine new supply routes or develop ex-isting entry points.

2014 was a very warm year. The temperatures were mild throughout the usual heating periods (in the winter, spring and autumn). This led to an excep-tional fall in gross consumption in 2014 throughout the zones supplied by GRTgaz (-16% as compared with 2013). The fall in gross consumption was mainly supported by the temperature-sensitive sec-tor of public distributions (-19% as compared with 2013). The fall also concerned consumption among

industrial customers linked directly to the GRTgaz network (-11% as compared with 2013), some of whom are particularly temperature sensitive (elec-tricity generation, cogeneration, urban heating and the motor vehicle sector). Gas demand for elec-tricity generation was especially slack in 2014: on the one hand, gas prices were not very competitive for electricity generation as compared with those of coal and imported electricity; and on the other

2.2 decreasing consumptions in 2014

ORIGIN OF FRANCE'S GAS SUPPLY IN 2014

Qatar OtherAlgeriaRussiaNetherlandsNorway

28% 38%

11%12%

9%

2%

SoeS 2014

_ 29


hand, there were no periods of very cold weather requiring electricity generation by gas-fired power plants in 2014. In this context of weather tempera-tures well above normal, consumption corrected for weather effects for the public distribution networks is down (of about -2% as compared with 2013).

The temperatures recorded for the first half of 2015 were close to normal, in particular during the 2014-2015 winter. Over that period, con-sumption rose as compared with 2014, but with-out reaching the 2010-2013 levels. The economic context does not show any marked signs of recovery, and the efforts to enhance energy efficiency continue to produce their effects.

In the summer of 2015, an increase in gas con-sumption for electricity generation was noted during spells of very hot weather, leading to an overall rise in gas consumption over a period in which no heating is required and industry slows down for the holidays.

BREAKDOWN OF CONSUMPTION WITHIN INDUSTRY

Cars - TyresChemicals - OilAgri-food industriesPaper

OtherElectricity - District heatingMetallurgyGlass - Non-metallic materials

15

56

23

24

19

13

7

CHANGE IN GROSS NATURAL GAS CONSUMPTION IN THE GRTGAZ ZONE

TWh/year

Centralised electricity productionPublic distribution networksIndustrial transport clients

600

500

400

300

200

100

02005 2006 2007 2008 2009 2010 2011 2012 2013 2014

30 _


After a year of national discussions on the energy transition, the LTECV law was passed by the French parliament on 22 July 2015. The law covers the following main points:

• bring the proportion of nuclear energy used in electricity generation o 50% by 2025: accom-panied by development of renewable energy sources (wind power and photovoltaic systems), this corresponds to a change in the energy mix for electricity generation, in which gas plays an accompanying role;

• reduce final energy consumption of fossil fuels by 30% by 2030: this measure concerns natural gas, and also products derived from crude oil and coal. Natural gas is recognised as producing the lowest levels of CO2 emissions among fossil fuels, under equivalent use;

• ongoing, enhanced efforts to reduce energy consumption through building renovations to make them more energy efficient;

• further backing for renewable energy sources: in particular for their financing and their economic integration in the energy mix. This hence also concerns development of biomethane;

• a change in governance: This includes develop-ment of a low-carbon strategy (with constitu-tion of scenarios regarding framework energy demand) and implementation of a Pluriannual Energy Programme;

• for the transport sector: The law aims at reduced energy consumption and diversification of energy sources, with a marked concern as to improving air quality; it suggests accelerating development of alternative energy sources to crude oil, including electric vehicles and also gas-powered vehicles.

To help to constitute a low-carbon energy mix, natural gas can play a major part in the following fields:

• gas-powered mobility: diversifying the trans-port energy mix to help to absorb local pollu-tion (particles), give vehicles a sufficient range, and reduce CO2 emissions. Gas is indeed a fuel that is accessible for heavy goods and passenger vehicles (buses, coaches, dustbin lorries, other heavy good vehicles) and light vehicles (light goods vehicles, taxis, car pooling, private vehi-cles). The technology can also be developed for boats on waterways;

• gas-fired heating: to reduce the effects of temperature sensitivity for buildings with electric heating systems on electricity generation at peak periods (and hence reduce CO2 emissions and invest-ments in peak period generation resources and electricity infrastructures). Gas-fired heating for new and renovated housing is energy-efficient;

• use of gas in industry, where it is useful to keep gas prices competitive when supplying industrial facilities, with the added advantage of cutting emission levels of CO2 and other pollutants as compared with coal or fuel oil;

• centralised gas-fired power generation: as a complement to renewable energy sources and nuclear power depending on their evolutions, gas-fired power plants significantly reduce emis-sion levels of CO2 and other pollutants as com-pared with coal or fuel oil;

• gas-fired cogeneration, which enables use of the heat produced during electricity generation: co-generation is used in industry, service buildings and housing (heating and domestic hot water);

• renewable gas: biomethane and Power to Gas solutions (synthesised methane made using ex-cess electricity generated by renewable energy sources) will progressively meet an increasing share of demand.

2.3 the role of gas in the energy transition

_ 31


To anticipate demand for gas, GRTgaz evaluates the ten-year trends as to consumption for the con-sumers connected to its transmission network and to the distribution networks that it serves, per cus-tomer typology: residential, services, industry, cen-tralised electricity generation and cogeneration.

GRTgaz draws up a reference scenario with a choice of hypotheses in compliance with the probable evolution in the structural, economic

and regulatory context. This scenario takes into account the regulations in force, and it includes in particular efforts that are bearable for households and industry in terms of cutting energy consump-tion and enhancing energy efficiency.

In parallel to the reference scenario, GRTgaz puts forward contrasting alternative scenarios illus-trating the extreme situations of a low scenario (Green Mix) and a high scenario (Diversified Uses).

2.4 gas demand forecast

Reference scenario for the 2015-2030 period: Gas consumption will remain stable until 2030

Forecast change in gas demand within the GRTgaz perimeter (hypotheses drawn up in July 2015)

TWh 2014 (1) 2015 2020 2023 2024 2030MAGR (2)

2015-2024MAGR

2015-2030

Service and residential sector (3) 229 229 222 215 212 196 -0.8% -1.0%

Industrial sector (3) 157 166 159 157 156 151 -0.7% -0.6%

Centralised electricity generationand cogeneration

32 43 47 53 56 119 +3.1% +7.0%

Transmission system operators’ own consumption

4 4 4 4 4 -4 - -

Total 422 441 433 429 429 471 -0.3% 0.4%

1. Actual consumption levels. 2. MAGR: Mean annual growth rate. 3. Excluding cogeneration.

COMPARISON OF DEMAND ASSUMPTIONS ESTABLISHED IN 2014 AND 2015

GRTgaz 2015 assumptions GRTgaz 2014 assumptions Actual 2006 to 2014

600

500

400

300

200

100

0

Total consumption - GRTgaz zone

Residential and tertiary sectors

Industrial sector

Centralised electricity production and cogeneration

20062007

20082009

20102011

20122013

20142015

20162017

20182019

20202021

20222023

20242025

TWh

32 _


Key assumptions for the 2015-2024 period

• Residential and services: -0.8% per yearThe implementation of regulations stemming from the recent environmental policies in the energy field (Energy transition, following on from the Energy-climate package and the Grenelle Environ-ment agreements) should translate into lower unit consumption, partly compensated by increases in the numbers of building units available.

Indeed, the efficiency of the gas-fired equipment used for heating, cooking and production of do-mestic hot water are compatible with the ener-gy efficiency standards for new buildings. Since implementation of the 2012 Thermal regulations, the market share for gas in new buildings has risen. For the future thermal regulations, the share of gas in the residential and services energy mix will depend on a calculation of CO2 emission levels to compare direct use of gas in buildings and equivalent use of electricity.

• Industry: -0.7% per yearThis hypothesis takes into account the structural evolution for the main segments of industrial ac-tivity (10) and the effects of the successive econo-mic slowdowns (in 2008-2009 and since the end of 2011) for some of them. It integrated energy savings, energy substitutions and development of new uses for natural gas, in particular process heat and production of hydrogen.

In industry, apart from use of gas in chemicals as a raw material (production of hydrogen, produc-tion of fertilisers and other molecules used in ba-sic chemicals), gas is used to produce heat and apply thermal treatments, for which it could be replaced by other energy sources (electricity, coal, crude oil, biomass). The evolution in the market

share of gas for these uses hence depends on its environmental performance levels (equipment ef-ficiency - emissions of CO2 -; emission levels of pollutants - NOx, SOx, particles, etc. -) and on its economic performance levels as compared with those of the other energy sources available. To as-sess the comparative competitiveness of gas for industrial consumers, it is necessary to complete the aspects directly linked to energy prices by exa- mining the impact of technological, logistics and infrastructure costs, plus the effects of the regula-tions and the accompanying taxes.

• Electricity generation: +3.1% per yearThe hypotheses concerning electricity generation adopted by GRTgaz for the reference scenario are coherent with the RTE data concerning the installed capacity and the quantities of electricity generated over the 2015-2020, as set out in its 2015 forecast. Moving beyond 2020, the hypotheses adopted by GRTgaz are coherent, concerning the installed capacity and the quantities of electricity generated, with those of the New Mix scenario set out in the 2014 RTE forecast. These hypotheses take into account the boost given by the LTECV law, with the reduction in the share of electricity generated by nuclear plants to 50% by 2025 and development of renewable energy sources.

In 2015, 13 combined cycle gas turbines (CCGT), representing an installed capacity of about 5.7 GWe, were connected to the GRTgaz net-work. Open-cycle combustion turbines (CTs) with a combined power rating of about 0.8 GWe are located on three sites (Gennevilliers, Montereau and Vitry-sur-Seine).

Over the 2015-2020 period, in coherence with the RTE hypotheses, the installed centralised elec-tricity generation capacity will be completed by

10. Motor vehicles and tyres, oil product chemicals, glass and materials, metal production, paper, agri-food.

_ 33


commissioning two units: a 514 MWe plant at Bouchain (Nord département) is due to be put into service in 2016 and another of 422 MWe at Landivisiau near Brest in 2018.

After 2020, the RTE New Mix scenario mentions the need for new capacity to ensure the balance of the electricity system by 2030: 7 GWe of peak level resources (which can be generation or consumption-cutting resources) and 4 GWe of semi-basic level resources. GRTgaz has adopted the hypothesis involving construction of 10 com-bustion turbines with a unit power rating of 150 to 200 MWe between 2023 and 2026, and con-struction of 7 combined cycle gas turbines be-tween 2025 and 2030, corresponding to 9.4 GWe of installed capacity regarding combined cycle gas turbines by 2030.

The quantities of electricity generated as calculat-ed by RTE are translated into volumes of gas, con-sidering an efficiency level 53% for combined cy-cle gas turbines and 40% for combustion turbines.

Gas demand for electricity generating units stands at 17.8 TWh in 2015, and then reaches a plateau at 20 TWh/year until 2020.

From 2020 on, GRTgaz forecasts a fresh rise in gas-fired electricity generation with a gradual re-turn to annual durations of use for the installed electrical capacity capacity of about 4,000 h. In-deed, limitation of the operating durations for oil- and coal-fired plants and development of the share of intermittent renewable energy sources in electricity generation, could progressively lead to enhanced use of gas-fired plants. Implementa-tion in 2017 of a system involving remuneration of electrical capacity made available to meet peak electricity consumption levels should also provide support for gas-fired power plants.

Thus between 2020 and 2025, demand for gas will increase progressively to reach 30 TWh in 2025. From 2025 on, with progressive commis-sioning of 5 or 6 combined cycle gas turbines, the volumes consumed will increase to 90 TWh by 2030.

For cogeneration systems, after the phase of uncertainty linked to the deadlines for renew-al of most of the electricity purchase obligation contracts between 2008 and 2013, GRTgaz had advanced the hypothesis that 1/3 of the installed power as at 2008 would be used on the electricity market, 1/3 renovated and kept under contract, and 1/3 closed. Thus by 2023, cogeneration con-sumption could remain stable, close to its 2013 level, at almost 30 TWh.

GAS-FIRED POWER PLANTS

Montoir-de-Bretagne

Landivisiau

DK6

Bouchain

Pont-sur-SambreÉmile huchet

Blénod

Toul

Bayet

Combigolfe

Martigues Cycofos

1

1

1

2

1

1

1

1

12

2

1

Plant in operation on 1 January 2015

Plant planned or under construction

Number of groups per site

GRTgaz and RTE

34 _


As GRTgaz is responsible for strategic infrastruc-tures concerning security of energy supply, it must be able to respond to increases in the volumes of gas transmitted during a cold winter or very low temperatures for three days, which can occur sta-tistically every 50 years (11).

GRTgaz has to size its network, and in particu-lar its regional network, to ensure that its delivery and exit capacity is available and sufficient to meet these obligations.

The daily consumption called during such cold spells, the “2% peak risk” or P2, is evaluated for the past year by extrapolating the winter con-sumption levels at the extreme temperature using a method known as the “winter analysis” method.

GRTgaz has also consulted the distribution system operators and the industrial consumers directly connected to its network to determine the evo-lution in their peak consumption levels over the next 5 years (12). After more than 5 years, the evo-

2.5 public service obligations in the event of exceptionally cold spells

11. French order No. 2004-251 dated 19 March 2004 as modified covering public service obligations in the gas sector.

12. In 2014, the period of information covered 3 years, but it has now been extended to 5 years.

FORECAST EVOLUTION IN PEAK GAS DEMAND ON THE GRTgaz NETWORK (Hypotheses drawn up in July 2015)

MAGR 2015/16 2024/25

MAGR 2015/16 2030/31 2014/15 2015/16 2020/21 2023/24 2024/25 2030/31

TOTAL

Gas year (1) (TWh) -0.3% 0.4% 438 442 431 429 432 471

Total P2 (2) (GWh/d) -0.3% -0.1% 3,960 4,030 3,991 3,930 3,909 3,995

Firm P2 (GWh/d) -0.3% -0.1% 3,898 3,968 3,929 3,868 3,847 3,932

Public distributions

Gas year (TWh) -0.7% -1.1% 283 282 274 267 265 241

Total P2 (GWh/d) -0.8% -1.1% 3,053 3,064 2,950 2,874 2,846 2,592

Firm P2 (GWh/d) -0.8% -1.1% 3,053 3,064 2,950 2,874 2,846 2,592

Direct customers

Gas year (TWh) +0.5% +2.5% 154 158 154 160 165 228

Total P2 (GWh/d) +1.1% +2.5% 907 966 1,041 1,056 1,063 1,403

Firm P2 (GWh/d) +1.1% +2.7% 845 904 979 994 1,001 1,341

GRTgaz consumption

Gas year (TWh) - - 2 2 2 2 2 2

Total P2 (GWh/d) - - 17 17 17 17 17 17

Firm P2 (GWh/d) - - 17 17 17 17 17 17

1. From 1 November to the 31 October of the following year.2. Gas demand during 2% risk cold spells.

_ 35


lution is considered as following that of the annu-

al consumption levels by volume established per

type of consumer and per sector of activity.

In application of article 2-III of the French order

dated 16 June 2014 covering methods for deter-

mining gas supply obligations, the estimation as

to the value of the gas supply obligation for all the suppliers to meet the peak daily consumer re-quirements is calculated by applying a normative aggregation ratio (95.5%) to the estimated value of daily consumption at peak levels for each of the customers coming under article 4 of the French order dated 19 March 2004.

FORECAST EVOLUTION IN PEAK GAS SUPPLY REQUIREMENTS ON THE GRTgaz NETWORK (Reference scenario)

MAGR 2015/16 2030/31 2014/15 2015/16 2020/21 2023/24 2024/25 2030/31

TOTAL

Aggregated firm P2 (GWh/d) -0.3% 3,722 3,789 3,752 3,673 3,694 3,755

Firm P2 (GWh/d) -0.3% 3,898 3,968 3,929 3,847 3,868 3,932

COMPARISON OF PEAK DEMAND ASSUMPTIONS ESTABLISHED IN 2014 AND 2015

GRTgaz - July 2015 GRTgaz - July 2014 Historical

Total - GRTgaz zone

Public distribution networks

Industrial clients

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

2005-06

2006-07

2007-08

2008-09

2009-10

2010-11

2011-12

2012-13

2013-14

2014-15

2015-16

2016-17

2017-18

2018-19

2019-20

2020-21

2021-22

2022-23

2023-24

2024-25

P2 p

oint

in G

Wh/

d

36 _


As a complement to the reference scenario, GRT-gaz puts forward two alternative scenarios for gas demand up to 2030:

• a low scenario, entitled Less 30;

• a high scenario, entitled Diversified Uses.

The GRTgaz reference scenario and the alternative scenarios are compared below with the scenario accompanying implementation of the Energy tran-sition: scenario AMS2, ie “with further measures 2”, proposed by the Directorate general for energy and the climate. This last scenario has been reconstructed on the basis of the public information available.

These scenarios illustrate the effect that active measures could have on gas demand over the medium term.

Two alternative scenarios for the period up to 2030

• The Less 30 scenario – low trajectoryThis scenario considers the effects of the new en-vironmental regulations oriented mainly towards reducing gas consumption levels, and hence con-stitutes a minimum trajectory for gas demand be-tween 2015 and 2030. The objective of cutting fos-sil fuel consumption by 30% is applied to gas uses without taking into account its enhanced environ-mental performance as compared with crude oil or coal. The technological and economic efforts are placed at the limits of capacities regarding house-holds and economic and industrial actors, and they would only seem conceivable under application of particularly stringent regulatory constraints.

The Less 30 scenario also integrates development of gas as a fuel for transport, and takes into account the objective of limiting the share of electricity generation from nuclear plants to 50% by 2025, together with development of renewable energy sources.

• The Diversified Uses scenario – high trajectory

In this scenario, gas resources are more widely available on the market, with a return of LNG flows to Europe and enhanced competitiveness for gas. Gas is used for electricity generation as a complement to renewable energy sources with a longer annual duration of use; its use also pro-gresses in industry and for heating in housing and services buildings as a replacement for energy sources whose environmental and economic ba-lance is less favourable. Active backing is provided for development of gas as a fuel for transport. Similar backing is also provided for development of production and injection of renewable gas, biomethane and Power to Gas.

In this way, with diversified uses and resources extended to include renewable gas, gas and its infrastructures make an even bigger contribu-tion to the energy transition and the low-carbon strategy.

• Scenario AMS2– reference of the DGEC for the Energy transition

The Directorate general for energy and the cli-mate (DGEC) coordinates (13) an exercise to model levels of energy consumption and emissions of greenhouse gases and pollutants. The origins of these prospective DGEC scenarios are to be found in the European regulatory obligations (14). Their purpose is to enable evaluation of the impact of the measures linked to the energy transition.

Within this framework, three scenarios have been examined by the DGEC:

- scenario AME, “with existing measures”: pro-jection taking into account the effects, in terms of reductions in greenhouse gas emissions, of the policies and measures adopted and imple-mented before 1 January 2014;

2.6 the alternative scenarios for the period up to 2030

13. With the help of the ADEME, the CGDD, Enerdata, the CITEPA, Energies-Demain, Armines and Seureco.

14. Regulation EU-525/2013: Monitoring and reporting greenhouse gas emissions by the member countries.

_ 37


- scenarios AMS “with further measures” 1 and 2: two projections that take into account the effects, in terms of reductions in greenhouse gas emissions, of the policies and measures adopted and implemented to reduce global warming, to-gether with the policies and measures planned for the purpose: for AMS1, this covers measures that can be modelled directly; for AMS2, it in-volves taking into account, after quantification, all the effects of the regulatory evolutions linked to the energy transition.

Scenario AMS2 is the most appropriate for ap-proaching a low scenario for gas. The main objec-tives modelled in AMS2 are as follows:

- reducing greenhouse gas emissions by 40% be-tween 1990 and 2030 (2015-2035 trajectory compatible with reaching the “factor 4” objec-tive by 2050);

- reducing final consumption by 20% in 2030 as compared with 2012;

- reducing final consumption by 50% in 2050 as compared with 2012;

- reducing consumption of fossil fuels by 30% in 2030 as compared with 2012;

- reaching 23% of energy from renewable sources in final energy consumption by 2020 and 32% by 2030, including 40% for electricity, 38% of heat consumed, 15% of fuels and 10% of the gas consumed;

- reducing the share of electricity generation by nuclear plants to 50% by 2025.

Comparison of the scenarios: total consumption and peak daily consumption

The following graphs show the evolution of an-nual consumption and peak daily demand for the reference scenario ( ), the alternative scenarios LESS 30 ( ) and Diversified Uses ( ), and sce-nario AMS2 ( ).

The reference scenario is shown with two variants to illustrate with sensitivity development of gas as a fuel for gas mobility: the reference trajectory ( ); and the active trajectory ( ).

The graphs show trajectories over the period of the GRTgaz ten-year plan from 2015 to 2024 and they are then extended for information purposes up to 2030.

PEAK DAILY CONSUMPTION (GWh/d)

Diversi�ed usage scenario - without new power plants after 2020WFM2 scenario - without new power plants after 2020

Less 30 scenario (LTE) Diversi�ed Uses scenario

GRTgaz-2015 scenario (reference) WFM2 scenario

5,000

4,500

4,000

3,500

3,000

2,500

2,000

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

GWh/d700

600

500

400

300

200

100

0

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh


Less 30 scenario (LTE) Diversi�ed Uses scenario

GRTgaz-2015 scenario (reference) AMS2 - DGEC scenario

TOTAL CONSUMPTION (TWh)

38 _


The peak daily consumption saw a low point in 2014, mainly due to reductions in the electricity generation capacity that were mothballed in 2013 and 2014.

Total consumption also saw a low point in 2014, due to a fall in consumption for the industrial customers connected directly to the GRTgaz net-work, not corrected for climate effects, contrary to the consumers linked to the public distribution system fed by the GRTgaz transmission network, corrected for climate effects to view the evolu-tions independently of climate effects.

The four scenarios are spread regularly over the 2015-2024 period with the GRTgaz low scenario (Less 30: 400 TWh in 2024), the GRTgaz high scenario (Diversified uses: 483 TWh in 2024), and, between the two, the GRTgaz reference scenario and its variant with enhanced gas-powered mo-bility (429/433 TWh in 2024). Scenario AMS2 is located below the GRTgaz low scenario, mainly due to a difference in consumption levels for the industry segment.

All the scenarios forecast a jump in 2025 corresponding to the cumulative effects of development of gas-fired power generation (linked to the re-duction of nuclear energy and to the development of renewable energy sources) and development of use of gas as a transport fuel.

Evolution in gas consumption (fossil fuel share)

not including electricity generation (15) between

2012 and 2030

GRTgaz reference

Diversified uses Less 30 AMS2

-21% -10% -27% -43%

To compare the evolution in demand for imported gas under these different scenarios as compared with the objectives of the LTECV law, we calculate consumption not including electricity generation, from which we deduct injection of biomethane

taken as standing at 10% (which corresponds to the objectives concerning development of re-newable energy sources for gas in the LTECV law). The share of gas consumption linked to electricity generation depends on the choices made for the energy mix concerning electricity generation.

The GRTgaz reference scenario and the Less 30 scenario are hence close to the energy transition objectives. Scenario AMS2 would seem to have a considerable impact on gas due to its very low trajectory for industry.

• Comparison of the scenarios: Residential and services sector

For the residential and services segment, we do not note any marked low points in 2014. The effects of the warm weather in 2014 have been erased by the climate correction made to the con-sumption levels of the public distribution systems, in which almost all the residential and services consumers are to be found.

For the GRTgaz reference scenario, the decrease in demand averages -0.8% per year. For the Less 30 and AMS2 scenarios, the trend is twice that size.

15. Taking into account injection of biomethane at a level of 10%.

Diversi�ed Uses - Residential and TertiaryGRTgaz-2015 (reference) - Residential and TertiaryLess 30 (LTE) - Residential and TertiaryWFM2 - Residential and Tertiary

RESIDENTIAL AND TERTIARY (TWh)

300

250

200

150

100

50

0

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

_ 39


In spite of differences in parameterising the evolu-tions in numbers of buildings and the effects of the efforts to enhance energy efficiency, the trajectories of the Less 30 and AMS2 scenarios are very similar.

Over the 2015-2030 period, the hypotheses concerning new buildings and renovation work (taking all buildings and all energy sources toge-ther) are more moderate in the GRTgaz scenarios as compared with the proactive values used in scenario AMS2.

The consumption trajectory for the Diversified Uses scenario is stable, taking into account more moderate rates of renovation work and a larger share of transfer of the heating and domestic hot

water uses from electricity to gas. In this scenario, the existing gas infrastructures cover a shift in consumption levels stemming from a switch to gas from other energy sources.

Evolution in demand between 2012 and 2030

in the residential and services sector

GRTgaz reference

Diversified uses Less 30 AMS2

-27% -16% -42% -43%

Over the residential and services perimeter, the GRTgaz reference scenario and the Less 30 sce-nario reach the energy transition objectives.

hypotheses of the different scenarios for new buildings and renovations

GRTgaz reference scenario: • about 300,000 new housing

units built per year;• and renovation of almost

250,000 housing units built before 2012 each year;

• a surface area of about 12 million m² of new service buildings put up each year;

• and renovation of service buildings at an annual rate of about 22 million m²;

• renovation brings gains in energy efficiency of 35% for housing units and 15% for services buildings.

Less 30 scenario• about 355,000 new housing





• renovation brings gains in energy efficiency of 35% for housing units and 15% for services buildings

Diversified Uses scenario• about 300,000 new housing






Scenario AMS2• new housing units per year:

2015-2016: 330,000; 2017-2021: 500,000; 2022-2030: 330,000;

• renovation of all housing units by 2030;




40 _


• Comparison of the scenarios: Industry sector

The main difference between the reference scenario and the Less 30 scenario lies in the levels of the efforts as to energy savings and efficiency made by the industrial concerns, and they are in fact fairly close. Indeed, as energy is one of the biggest cost items for industry, energy efficiency often leads to regular optimisation.

The Diversified Uses trajectory slows slight growth linked to higher rates of conversion to gas from other energy sources.

The AMS2 trajectory for industry is much lower than those of the other scenarios. In spite of a hy-pothesis as to evolution of value added for indus-trial production that is more favourable in scenario AMS2 (about +1.5%/year) than in the GRTgaz scenarios (about +0.7%/year), the industrial con-sumption levels in AMS2 are affected by a higher energy efficiency coefficient (estimated at -1.1%/year per tonne produced) than that in the GRTgaz scenarios (about -0.3%/year to -0.5%/year).

• Comparison of the scenarios: Electricity generation sector

From 2015 to 2020, the profiles of gas consump-tion for electricity generation in the GRTgaz reference, Less 30 and AMS2 scenarios are coherent with the quantities of electricity generated in the medium term 2015-2020 scenario of the RTE forecast.

After 2020, GRTgaz proposes a development tra-jectory for gas-fired electricity generation in which gas demand is coherent with the RTE New Mix scenario. This scenario includes the objective of reducing the share of generation by nuclear plants to 50% in 2025 and development of a large share of renewable energy sources.

To adapt the production/demand balance of the electricity network, manageable resources must be developed to accompany the highly intermit-tent power generation from wind power and photovoltaic systems. GRTgaz has established a hypothesis involving the construction of 10 com-bustion turbines (CTs) between 2023 and 2026

Diversi�ed Uses - IndustryGRTgaz-2015 (reference) - Industry

Less 30 (LTE) - IndustryWFM2 - Industry

INDUSTRY (TWh)

200

180

160

140

120

100

80

60

40

20

0

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

CENTRALISED ELECTRICITY PRODUCTION AND COGENERATION SITES (TWh)

180

160

140

120

100

80

60

40

200

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

Diversi�ed Uses - CEP + CogenGRTgaz-2015 (reference) - CEP + Cogen

Less 30 (LTE) - CEP + CogenWFM2 - CEP + Cogen

Trend without new construction after 2020

_ 41


and 7 combined cycle gas turbines (CCGTs) be-tween 2025 and 2030. The CCGTs are used for basic and semi-basic generation and their operation leads to gas consumption in proportion to their duration of use. The CTs are designed for short durations of use at peak periods, and in spite of their numbers, their consumption levels are low.

With these hypotheses, we hence observe a sharp rise in gas demand by 2025. The Diversified Uses scenario calls on a larger number of CCGTs as from 2025 (8 further CCGTs between 2025 and 2030) and cogeneration is further developed in that scenario.

We can note that these hypotheses, which stem from the RTE New Mix scenario, lead to almost dou-bling the installed capacity of the CCGTs, but this development is accompanied by a reduction in the number of coal-fired plants. For electricity generation, the CO2 emission factor for gas is close to half that of coal, so doubling the installed capacity would lead to stable levels of CO2 emissions.

GRTgaz also proposes a low trajectory for electric-ity generation, for information purposes, without any construction of new electricital capacity, un-der which the installed capacity and the quantities of gas consumed would remain at their 2020 le-vels until 2030. Although in theory this scenario is possible, it would currently seem highly unlikely in the framework of energy transition.

• Comparison of the scenarios: Gas-powered mobility

Compared with the other energy sources available to diversify the energy mix for the transport sec-tor (currently mainly provided by products derived from crude oil), use of gas as a fuel has the fol-lowing advantages: it enables resorption of local pollution (particles) and helps to reduce CO2 emis-

sions. It provides sufficient autonomy for vehicles - heavy goods and passenger vehicles (buses, coaches, dustbin lorries, other heavy goods vehi-cles) and light vehicles (light goods vehicles, taxis, car pooling, private vehicles).

The environmental balance is even more favour-able if the gas used as a fuel consists of biome-thane.

Jointly with GrDF, GRTgaz has drawn up two tra-jectories for gas demand as part of development of gas-powered mobility:

• a reference trajectory reaching almost 12 TWh in 2030;

• an active trajectory reaching 35 TWh in 2030.

The GRTgaz reference scenario has been drawn up using the two gas-powered mobility variants. For the Diversified Uses scenario, we have used the reference trajectory. The LESS 30 scenario uses the active trajectory, as gas used as a fuel is indeed a solution that enables the objectives of the ener-gy transition and a low-carbon mix to be reached overall.

GAS MOBILITY (TWh)

50

45

40

35

30

25

20

15

10

0

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

Diversi�ed Uses scenarioGRTgaz-2015 scenario (reference)

Less 30 scenario (LTE)WFM2 - DGEC scenario


42 _


To pilot development in use of gas as a fuel be-yond the traditional uses (“back-to-base” operating mode), a network of refuelling stations with public access is necessary. This is requested under the “Alternative Fuels Infrastructure” European directive1 which recommends that each Member State should draw up a plan covering deployment of public refuelling stations for electricity and gas by November 2016. Thanks to implementation of industrial partnerships and to internal skills in the fields of engineering and technical expertise concerning compression, GRTgaz accompanies the project stakeholders and helps to boost the activity by promoting an essential network of gas refuelling stations that meet the requirements of all types of vehicles. Emergence of use of gas as a fuel other than for captive fleets would entail a network of about 1,000 stations, or 10% of the current distribution system, accessible to the pub-lic and housed for the most part in the existing multi-fuel stations.

To make a comparison, other countries in Eu-rope have undertaken active policies: Italy has 850 public stations, Germany has 900 and Swit-zerland has 140. These refuelling points would be profitable once the number of equivalent light vehicles reaches one million (1,000 light vehicles per station), i.e. ~3% of the vehicles on the roads in France.

• Renewable gas scenariosRegarding gas demand, the forecasts concerning production of renewable gas complete the over-view as to the role of gas infrastructures in the energy transition.

Added to the favourable environmental properties of natural gas as compared with other fossil fuels, injection of renewable gas further enhances the carbon footprint of gas.

GRTgaz is developing two lines of industrial ac-tivities:

- biomethane, with gradual connection of increas-ing numbers of biomethane producers in the near future;

- examination of Power to gas, with a project un-der way involving a pilot installation producing synthesised methane by using excess electricity from renewable sources at Fos-sur-Mer in 2018.

Biomethane activityLocal production of biomethane lies well within the dynamics of the energy and ecological tran-sition. It helps to reduce greenhouse gas emis-sions, recycle waste and reduce our natural gas imports.

Biomethane corresponds to biogas that has been treated to meet the required specifications for its injection in the networks. The biogas stems from decomposition of organic waste (household waste, organic farming substances, sludge from sewage treatment plants, etc.). Biomethane can be injected in the transmission network or the distribution system. Biomethane producers can benefit from a regulated purchase price that is guaranteed for 15 years if they inject the gas into the networks.

The LTECV law sets the target of increasing the share of renewable energy sources to 10% of the gas consumption in France by 2030. The ADEME studies have confirmed the existing po-

INJECTED BIOMETHANE (TWh) WITHIN THE GRTGAZ ZONE

25

20

15

10

5

0

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

TWh

Biomethane trend scenario - total in GRTgaz zone

Biomethane deliberate scenario - total in GRTgaz zone

Biomethane deliberate scenario - Distribution

Biomethane deliberate scenario - Transmission

Biomethane trend scenario - Distribution

Biomethane trend scenario - Transmission

_ 43


tential for development in France. GRTgaz relies on two hypotheses when forecasting injections of biomethane in the gas networks:

- a Trend hypothesis 12 TWh injected in France by 2030, including 9 TWh within the GRTgaz perimeter;

- an Active hypothesis 30 TWh injected in France by 2030, including 22.5 TWh within the GRTgaz perimeter.

By the end of 2015, twenty or so projects will be in service in France, including the Chagny pro-ject (Saône et Loire département), which injects about 28 GWh/year in the GRTgaz network. Un-der the current trend, a boost in activity levels is expected by around 2022-2023. Between 2015 and 2018, the trajectory corresponds to the projects identified by the network operators. By 2020, execution of the projects in the portfo-lio could represent up to 1 TWh/year of biomethane injected in the GRTgaz network. Beyond that date, the trajectories are projected to fol-low the guidelines drawn up by the ADEME up to 2030.

Power to gas activityThe Power to gas activity enables storage of the quantities of electricity from renewable sources (wind power and photovoltaic systems) when their generation outstrips demand.

The underlying principle is that of converting elec-tricity into hydrogen through water electrolysis. The hydrogen is then converted into synthesised meth-ane through association with CO2 recovery after capture of CO2 emissions stemming from indus-trial, farming or electricity generation processes). The synthesised methane produced is by nature a renewable gas. It is injected in the gas networks.

Construction of a demonstration plant is sche-duled for 2018 at Fos-sur-Mer.

By 2030, 100 Power to gas installations could be set up to enable storage of 2.5 to 3 TWhe of renewable surplus electricity. By 2050, develop-ment of 1,000 installations could enable storage of almost 25 TWhe of electricity out of a poten-tial surplus of renewable electricity estimated at between 25 and 75 TWhe.

Since the opening of the natural gas market in Europe, consumers have had the right to choose their gas supplier. GRTgaz’s mission is to transmit its shippers customers’ natural gas under the best possible cost, reliability and safety conditions. The company facilitates market access and favours a balance between the offer and demand for gas.

For this purpose, in 2008, GRTgaz and TIGF have maintained a continuous dialogue with all market players.

A regularly simplified entry/exit model

The transmission offer of GRTgaz allows gas ship-pers to supply industrial sites and public distribu-tion systems connected to the transmission net-

2.7 the transmission offer of grtgaz

a dynamic market, satisfied clientsThe dynamism of the wholesale market has been confirmed with 640 TWh transferred at GRTgaz Title Transfer Points in 2014: up 3.9% on 2013 and a volume that has doub-led over a period of four years.

GRTgaz clients are satisfied:• with the business relationship (95% of

clients);• with the quality of the transmission and

delivery offers and services (92% of clients).

2014 satisfaction survey

44 _


work, to ship gas through France or to carry out transactions with other parties. GRTgaz markets these transmission services:

• in the form of access capacity at the network’s entry and exit points and on the North-South link. In each Zone, shippers may freely inject or withdraw gas for their customer deliveries;

• in the form of access to a Title Transfer Point (PEG): these points allow shippers to transfer gas, without having to indicate its source or destination, and access a gas trading managed by Powernext.

Their only obligation is to balance entries and withdrawals over the gas day. This model guarantees flexible market operations and favours in-creased competition.

Towards a single market zone

The existence of several entry/exit zones reflects the physical limits of the network and, in some ca-ses, the impossibility of transmitting gas between an entry point in one zone and an exit point in an-other zone. Thanks to its investments, GRTgaz has reduced its number of balancing zones from four in 2005 to two in 2009. After completing the inte-gration of the L-gas Balancing Zone in April 2013, this simplification process continued with the launch of a common marketplace between GRTgaz South and TIGF on 1 April 2015. CRE guidelines published in May 2014 foresee the creation of a single wholesale market in France by 2018.

A balancing system modernised in accordance with European rules

In 2015, GRTgaz implemented market-oriented balancing systems as foreseen in the European Network Code. Since April 2015, shippers have had access to more information and forecasts on the system’s equilibrium level and have had to play a role in maintaining the system’s global ba-lance. As from October 2015, market players will be entirely responsible for balancing the GRTgaz system, without any tolerance devices. GRTgaz has developed a service, called ALIZES, that allows the market to benefit from the flexibility permit-ted for global line-pack.

In parallel to this, the transmission offer of GRT-gaz will grow at the beginning of 2016 with the creation of a Network Interconnection Point at Alveringem and the connection of a new LNG ter-minal at Dunkirk.

Transparency and fluidity

Smart GRTgaz, an online service, is accessible to all and offers clients and prospects comprehen-

Montoir

Fos

Dunkirk LNG*

Alveringem* Taisnières HTaisnières B

Obergailbach

North-East

North B

North-West

North-Atlantic

South-Atlantic

South-East

Oltingue

Jura

Gassco

TIGF

Fluxys

Fluxswiss

Gaznat

Fosmax LNGElengy

Elengy

GRTgaz DeutschlandOpen grid Europe

* as from 1 November 2015

Direction of natural gas �ow �rm capacity in GWh/day

Network interconnection point

Transport LNG Terminal Interface Point

Transport Storage Interface Point

Adjacent system operatorOperator

PEG North

GRTgaz NETWORK IN 2015

_ 45


sive information so that they may optimise their capacity reservations and ensure their gas port-folio is balanced. It covers all interconnection points: borders, LNG terminals, storage facilities, the North-South link, consumption points, and offers more than 1,000 pieces of data in real time. Thanks to this reference information, Bloomberg and Reuters have chosen Smart GRTgaz to inform their subscribers.

Prisma is another example of the measures put in place

to create a veritable internal EU gas market. This platform facilitates the transmission of gas be-tween all European marketplaces, while offering the possibility to book joint or ‘bundled’ capacity online, in accordance with the CAM (16) network code, which will come into force in Novem-ber 2015. It also facilitates access to a secondary market for capacity exchange.

A total of 24 Transmission System Operators ope-rate as partners within PRISMA, while 35 offer their products; over 450 shippers are registered.

16. Capacity Allocation Management: network code that concerns the allocation of transmission capacity at the interconnection points.

The volume of gas transmitted by GRTgaz in 2014, a historically warm year, was slightly down on 2013. The preponderance of flows from the North to the South was confirmed:

• another fall in LNG deliveries (between 2011 and 2014, LNG imports dropped by 45%);

• a substantial fall in LNG imports in Spain, resul- ting in a significant and regular rise in gas flows towards the TIGF zone and Spain.

In light of this situation, transmission levels via the North-South link remain high. This link, which had become saturated, was only relieved at the very end of 2014 with a one-off delivery of LNG in the south of France.

Furthermore, entry levels at Taisnières outweighed those at Obergailbach, thereby reflecting the fall in demand for Russian gas.

Storage site replenishment was a little higher than in 2013 due to a winter-summer price spread that increased over the year.

2.8 demand for transmission capacity on the grtgaz network

North Zone

South Zone

TIGF

Montoir-de-Bretagne

Dunkirk

Obergailbach

Oltingue

Fos CavaouFos TonkinPirineos

Taisnières

-4 TWh

-52 TWh

+14 TWh

-13 TWh

+10 TWh

+18 TWh

+14 TWh

-3 TWh

H +47 TWhB -10 TWh

Direct �ow direction:Positive annual variationNegative annual variation



CHANGES IN THE PRINCIPAL FLOWS OF GAS IN 2014 VERSUS 2013

46 _


Use of capacity subscribed in 2014

To supply the French market at the lowest cost, shippers primarily use capacity subscribed on the North-South link, at Dunkirk and at Taisnières. Use of the Midi PIR point and the Oltingue exit point is slightly up while entry levels at Obergailbach and at LNG terminals are down.

It is worth noting that almost all Network Inter-connection Points (PIR) were used at least once at their maximum capacity.

Gas flow 2014 (TWh) 2013 (TWh)Change 2014/2013

(as a %)

Gaseous gas entry

Dunkirk 170 174 -2%

Taisnières H 163 116 29%

Taisnières B 41 51 -24%

Obergailbach 77 129 -68%

LNG entry

Montoir 9 12 -33%

Fos 61 74 -21%

North-South link and JTS 129 115 11%

Exit

Oltingue 29 15 48%

Midi 85 67 21%

Pirineos (1) 49 39 20%

Storage

Injection 92 92 -1%

Withdrawal 83 98 -18%

1. Data from TIGF (Larrau + Biriatou up to 30 September 2014).

North Zone

South Zone

TIGF

Montoir-de-Bretagne

Dunkirk

Obergailbach

Oltingue

Fos

Biriatou

Larrau

Taisnières

AA 86%DM 100%

AA 49%DM 100%

AA 35%DM 96%

AA 43%DM 88%

AA 77%DM 100%

AA 94%DM 100%

AA 7%DM 33%

H AA 81% DM 100%B AA 59% DM 100%

Direct �ow direction



AA : annual averageDM : daily maximum

USE OF CAPACITY IN 2014

_ 47


LNG: entry levels continue to plummet

Since the end of 2011, LNG supplies have continuously fallen as shipments have changed course for more lucrative markets in Asia. In 2014, ano-ther 33% fall at Montoir and a 21% fall at Fos confirmed this trend, despite a one-off increase in deliveries to LNG terminals at the end of the year, which was not repeated in France at the begin-ning of 2015.

Fall in entry levels at Obergailbach, to the benefit of Taisnières H

In 2014, entry levels fell by 52 TWh at Obergail-bach and increased by 47 TWh at Taisnières H. This switch reflects the fall in Russian imports due to the mild weather.

A fall in entry levels at Dunkirk and Taisnières L

Entry levels at Dunkirk fell by 2% in 2014 despite a very high capacity utilisation rate. Work asso-ciated with the connection of the Dunkirk LNG terminal reduced availability over the summer.

Entry levels at Taisnières L fell by 23% due to the weather, in particular.

Gas exit levels: significant increase at Oltingue and Midi

The Midi PIR point saw flows towards the TIGF zone increase by 18 TWh, the majority of which continued to Spain (10 TWh) while the rest was used to replenish TIGF storage sites, higher in 2014 than in 2013.

In 2015, a 35% rise in LNG imports in Spain, compared to the first half of 2014 (from 310 to 420 GWh/d), led to a fall in gas imports from France of almost 25% (from 122 to 94 GWh/d over the same period).

Gas exports towards Switzerland and Italy in-creased by 48% following a rise in prices on the Italian market. Since the end of 2013, prices have risen and returned to 2012 levels.

In November 2014, the replenishment level of sto-rage facilities was higher than in November 2013, in anticipation of a significant winter/summer price spread. Furthermore, in the winter of 2013/2014, shippers had found it difficult to strike a balance following an explosion in the North-South price spread, which rose to €16.77/MWh. Shippers there-fore preferred to replenish the storage facilities to prepare for a winter (2014/2015) during which LNG would not always be present in the South Zone.

PRICE SPREADS BETWEEN PSV (ITALY) AND PEG NORTH

10

-4

-2

0

2

4

6

8

Jan.

2012

Apr. 2

012

July

2012

Oct.

2012

Jan.

2013

Apr. 2

013

July

2013

Oct.

2013

Jan.

2014

Apr. 2

014

Jan.

2015

Apr. 2

015

July

2014

Oct.

2014

€/MWh

LEVEL OF REPLENISHMENT IN GWH (TIGF AND STORENGY)

140,000

0

20,000

40,000

60,000

80,000

100,000

120,000

Janu

ary

Febr

uary

Mar

ch

April

May

June July

Augu

stSe

ptem

ber

Octo

ber

Nove

mber

Dece

mber

20142013

GWh

48 _


FOS MONTOIR

71089,2).0219,5:2) ;(3(</4=942<>)/?0292@@2<4/*2

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

450

300

350

400

250

200

150

100

50

0

450

300

350

400

250

200

150

100

50

0

GWh/d GWh/d

Average monthly �ow Reduced technical capacity

DUNKIRK TAISNIÈRE H

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

800

600

700

500

400

300

200

100

0

700

500

400

600

300

200

100

0

GWh/d GWh/d


OBERGAILBACH TAISNIÈRE B

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

300

250

200

150

100

50

0

700

500

400

600

300

200

100

0

GWh/d GWh/d


Entr

y le

vels

_ 49


MIDI OLTINGUE

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

300

250

200

150

100

50

0

450

300

350

400

250

200

150

100

50

0

GWh/d GWh/d


THE NORTH-SOUTH LINKAVERAGE MONTHLY PRICES AT PEG NORTH AND PEG SOUTH

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay July

Sept

.N

ov.

Jan.

Mar

chM

ay

Jan.

Mar

chM

ayJuly

Sept

.N

ov.

2011 2012 2013 2014 2015

45

25

30

35

40

20

15

10

5

0

450

300

350

400

250

200

150

100

50

0

Jan.

2013

Mar

ch 2

013

May

201

3Ju

ly 20

13Se

pt. 2

013

Nov.

2013

Jan.

2014

Mar

ch 2

014

May

201

4Ju

ly 20

14Se

pt. 2

014

Nov.

2014

Jan.

2015

Mar

ch 2

015

May

201

5Ju

ly 20

15

GWh/d €/MWh

Average monthly �ow Reduced technical capacity PEG North PEG South

Exit

leve

ls

North-South link: less demand in the winter of 2014/2015

Once again, great demand was placed on the North-South link in 2014 with flows from the North to the South increasing by 14 TWh between 2013 and 2014, driven by the rise in deliveries towards Spain and the replenishment of storage sites in the South Zone. Nevertheless, pressure

on the link eased at the start of the winter of

2014/2015, allowing a large-scale withdrawal of

gas from storage sites in the south and a one-off

LNG delivery to Fos during this period. The fall in

pressure was also reflected in prices in the South

Zone; the difference in price between the South

and the North shrank considerably at the begin-

ning of the winter of 2014/2015.

50 _


NUMBER OF DAYS AT MAXIMUM USEANNUAL AVERAGE UTILISATION RATE OF THE NORTH-SOUTH LINK (AS A %)

100%

80%

60%

40%

20%

02010

64

20

99

194

22673

69

93 94 94

2011 2012 2013 2014 2010 2011 2012 2013 2014

NUMBER OF DAYS AT MAXIMUM USEANNUAL AVERAGE UTILISATION RATE OF THE NORTH-SOUTH LINK (AS A %)

100%

80%

60%

40%

20%

02010

64

20

99

194

22673

69

93 94 94

2011 2012 2013 2014 2010 2011 2012 2013 2014

improving access to the south zone

GRTgaz has taken several measures to improve access to the South Zone and it is working closely with adjacent transmis-sion, storage and LNG terminal operators to release new capacity on the North-South link.

• Since June 2013, the Joint Transport Storage (JTS) service, designed with Storengy, has provided an additional daily capacity of up to 32 GWh/d, which is auctioned. Thanks to this service, an additional 5.37 TWh was transmitted in 2014.

• Since April 2014, GRTgaz has offered 40 GWh/d in additional firm capacity as a replacement for interruptible capacity.

• The optimisation of flows between TIGF and GRTgaz allowed an addition-al firm monthly capacity of 20 GWh/d to be sold in the winter of 2014/2015 and improved the availability of inter-ruptible capacity that had already been sold.

• For the winter of 2015/2016, GRTgaz has once again auctioned 5 GWh/d of entry capacity in the South Zone out of Switzerland thanks to close coopera-tion with Swiss network operators, par-ticularly Gaznat.

The optimisation of flows between TIGF and GRTgaz must once again allow an additional firm monthly capacity of 20 GWh/d to be sold in the winter of 2015/2016 and improve the availability of interruptible capacity that has already been sold. The JTS service will be repeat-ed once again.

Analysis of subscriptions by entry/exit point

GRTgaz also uses the entry and exit point sub-scription rate analysis to determine the capacity development requirements of the network.

Over the period 2014-2024, these rates are gener-ally high and stable: on average, more than 90% of the long-term firm capacity offered is already booked for the period 2016-2020. Additional short-term firm capacity is offered to provide sup-plementary market arbitrage possibilities and to facilitate access to the market for new players.

_ 51


Firm capacity subscriptions for gaseous gas entry points

For 2016-2020, long-term capacity has been fully subscribed at Dunkirk; 90% of long-term capacity has been subscribed at Taisnières L, This high subscription rate is normal in light of the specific nature of these points (importing of Norwegian gas and the only entry point for L-gas delivery).

At Taisnières H and Obergailbach, 30 GWh/d of additional capacity was offered throughout most

of the winter, as foreseen in the network code re-lated to congestion management.

At the Midi PIR point, from TIGF towards GRTgaz, capacity increases made in 2013 in both direc-tions met requirements. With subscription rates of around 80%, they allowed the GRTgaz South Zone and the TIGF zone to merge in April 2015 while managing the risk of structural congestion.

EXIT POINTS

Jan.

2012

Jan.

2013

Jan.

2014

Jan.

2015

Jan.

2016

Jan.

2017

Jan.

2018

Jan.

2019

Jan.

2020

120%

100%

80%

60%

40%

20%

0

Oltingue Alveringhem Midi GRTgaz towards TIGF

GASEOUS GAS ENTRY POINTS

Jan.

2012

Jan.

2013

Jan.

2014

Jan.

2015

Jan.

2016

Jan.

2017

Jan.

2018

Jan.

2019

Jan.

2020

120%

100%

80%

60%

40%

20%

0

Dunkirk Taisnières H Obergailbach Midi TIGF towards GRTgazTaisnières B

52 _


Firm capacity subscriptions for LNG entry points

At the Montoir and Fos entry points, long-term subscription rates reach, on average, almost 90%.

At the new Dunkirk LNG entry point, reserved capacity totals 250 GWh/d.

Firm capacity subscriptions for exit points

At Oltingue, capacity has been fully subscribed.

At Alveringem, the long-term subscription rate is around 80%.

At the Midi PIR point, from GRTgaz towards TIGF, the highly seasonal nature of the link is reflected in subscription rates of close to 80% in the winter and 50% in the summer.

Capacity subscriptions for the North-South link

Firm capacity for the North-South link was in-creased to 270 GWh/d as from April 2014 by converting interruptible capacity to firm capacity, thanks to recent adjustments to the network.

In 2014, 40 GWh/d was set aside for large indus-trial consumers of gas. During auctions on the Prisma platform, demand substantially exceeded supply, creating an auction premium. GRTgaz responded to this demand by launching the JTS service and by creating entry capacity at PIR Jura, which provides access to the South Zone from Switzerland, thereby relieving the North-South link during the winter.

As from the winter of 2014/2015, the North-South link utilisation rate has fallen significantly. Due to these changes, the 2015 auctions were far less successful: the premiums were far lower than those of 2014 and, for the first time since 2011, some lots at quarterly auctions were not sold. The JTS service subscription rate has also fallen since the winter of 2014/2015 and quarterly auctions for entry capacity at PIR Jura did not give rise to any allocations.

Injection/withdrawal capacity subscriptions for underground storage facilities

Storage capacity served by GRTgaz is marketed every year by the operator, Storengy. GRTgaz allocates the corresponding injection and with-drawal capacity on the transmission network automatically. The introduction of monthly capacity products in 2013 and of quarterly products in 2014 lets storage clients adjust the alloca-tion of transmission capacity in accordance with the short-term services offered by the storage operator.

High winter/summer price spread forecasts and the balancing difficulties encountered the previ-ous winter following the explosion in the North-South price spread helped improve the replenish-ment rate at the end of the summer of 2014.

In 2015, this trend was reversed and, excluding new regulatory storage obligations placed on suppliers, demand for storage in France fell once again.

_ 53


FIRM CAPACITY PRICE ON THE NORTH-SOUTH LINK

270 GWh/d

01/04

/2013

01/04

/2014

01/10

/2014

01/10

/2015

01/10

/2016

01/10

/2017

01/10

/2018

Available

2014 quarterly auction tariff 2014 annual auction tariff Regulated tariff

2015 annual auction tariff2015 quarterly auction tariff

€2.96/MWh

€0.72/MWh

€3.54/MWh

≈ €3.90/MWh€0.57/MWh

€0.84/MWh €0.84/MWh

€2.39/MWh €1.81/MWh

€0.57/MWh

FIRM CAPACITY SUBSCRIPTIONS ON THE NORTH-SOUTH LINK IN THE SUMMER OF 2015

270

01/04

/2013

01/04

/2014

01/10

/2014

01/04

/2015

01/10

/2015

01/10

/2016

01/10

/2017

01/10

/2018

2015 auctions (annual and quarterly)Available

Short-term OSP Long-term OSP Large gas consumer OSP

Reserved capacity 2014 auctions (annual and quarterly)

98 GWh/d

131 GWh/d 104 GWh/j

74 GWh/d

65 GWh/d 46.5 GWh/d

41 GWh/d

38 GWh/d

26 GWh/d

61.5 GWh/d

13 GWh/d 27 GWh/d

77.5 GWh/d

40 GWh/d

126

GW

h/d

126

GW

h/d

152.

5 G

Wh/

d

54 _

DEVELOPMENT OF THE GRTgaz TRANSMISSION NETWORK

3

3.1

Developing the transmission network: processes and timelines

3.2

Project portfolio changes

3.3

A single marketplace in France in 2018

3.4

Developments in the North Zone

3.5

Developments in the South Zone

3.6

Other development projects

3.7

Infrastructure to be commissioned over the next three years (2015-2017)

3.8

Infrastructure commissioned after 2017

3.9

Forecast capacity development for 2015-2024

3.10

Meeting of demand for gas in France in 2024

The shale gas revolution, the Fukushima disas-ter, the Ukrainian crisis and the collapse in oil prices are all events with global reverberations that have shaken the European gas market over the past few years. Gas prices, sources and directions of flow in Europe have constantly changed. Such volatility supports the need for large entry and exit ca-pacity and a robust and flexible core network to guarantee, regardless of the circumstances, security of supply and access to the most competitive gas. Shippers must be able to choose between sources of gas without being too restricted by the network’s physical limits. In the longer term, additional imports that are required to make up for the fall in Europe-an production will also give rise to new flows within Europe and, most probably, new transmission infra-structure.

At the same time, gas consumption in and around 2030 is very uncertain due to the introduction of new energy policies in Europe, and in France, that aim to lower greenhouse gas emissions. It is there-fore even more difficult to assess the suitability of new investments. It is in this context that GRTgaz network development projects should be seen.

With regards to current projects, at the end of 2015, the new LNG terminal at Dunkirk and the transmission network infrastructure on which it de-pends will be commissioned. New exit capacity will also be created at the end of 2015 at Alveringem

with the commissioning of the Flanders pipeline, which will allow non-odorised gas to be transmit-ted towards Belgium. New entry capacity will be created from Switzerland and Italy at Oltingue in 2018 to connect the French and Italian marketplaces and to strength South-North flows.

Simplification of the French market is also taking place at the same time. The first step was taken in April 2015 with the introduction of the TRS, a common marketplace for the south of France. It will be completed in 2018 with the commission-ing of infrastructures under the Val de Saône and Gascogne-Midi projects. These infrastructures, de-signed to ease congestion on the North-South link, will allow a single marketplace to be created in France.

In 2021/2022, new interconnection points with Spain and Germany are envisaged to strengthen the North-South corridor in the west of Europe. Projects to increase regasification capacity at Fos and at Montoir are also envisaged in order to sup-ply LNG to the centre of Europe.

During the plan’s lifetime, developments on the GRTgaz network will have to be considered to en-sure continuity of supply for clients supplied with L-gas and, if necessary, to respond to energy transi-tion challenges (biomethane, generation of electrici-ty from natural gas, Power to Gas).

_ 55


Analysing demand and changes in demand lets GRTgaz identify the infrastructure that is required to:

• develop trading capacity with adjacent opera-tors: shippers, LNG terminal operators, storage site operators, biomethane producers;

• adapt the network to variations in supplies and flow configurations;

• respond to changes sought for the organisation of the market, with the eventual creation of a single balancing zone;

• respond to changes in consumption, particularly those related to the use of combined cycle pow-er plants (17), which require significant levels of intraday flexibility.

The development of the regional network is main-ly based on the coverage of transmission require-ments at the time of peak demand.

The development of the national network de-pends on changes in capacity requirements at zone entry/exit points. In order to create new

capacity, structures that connect to adjacent in-frastructure have to be built or strengthened and the core network has to be strengthened so it can transmit the additional flows of gas from any of a given zone’s entry points to any of its exit points.

In most cases, strengthening one core network structure meets the needs of several capacity de-velopment projects. The strengthening schedule therefore depends on the project that triggers the schedule. In some cases, the strengthening of the core network can be a gradual process, as illustrated by the developments on the North-South link.

Discussions with shippers and adjacent operators allow GRTgaz to measure development require-ments and schedule core network investments. A change in their schedule can also cause GRTgaz to adjust its programme accordingly.

Projects can also be affected by regulatory changes, world energy market developments and their impact on shippers, consumers and investors.

3.1 developing the transmission network: processes and timelines

17. A CCPP uses around 20 GWh/d (20 million KWh), i.e. the equivalent of the winter consumption of a city with 200,000 inhabitants.

Compression

Pipeline without public debate

Pipeline with public debate

MACRO PLAN FOR THE COMPLETION OF MAJOR TRANSMISSION PROJECTS

Year Y Y+1 Y+2 Y+3 Y+4 Y+5 Y+6…

Technical studies WorksConsultation and administrative and public procedures prior to authorisation

56 _


GRTgaz invested 663 million euros in 2014 to upgrade and expand its transmission net-work, optimise its robustness and flexibility, and increase its capacity with adjacent net-works.

Commissioned infrastructure

The infrastructure that has been commissioned will allow the new LNG terminal at Dunkirk to be connected and capacity with Belgium and Spain to be increased, in compliance with commitments made to the market:

In the case of Spain, the commissioning of the new compressor and interconnection station at Chazelles (Charente) helped increase capacity at Port-de-Larrau from 110 GWh/d to 165 GWh/d in the direction, France to Spain, and from 110 GWh/d to 165 GWh/d in the direction, Spain to France. The station received €48 m in funding from the European Union.

By the end of 2015, infrastructure that will con-nect the LNG terminal at Dunkirk and that will create an exit towards Belgium will be commis-sioned:• transmission line between Cuvilly and Dierrey;• Clipon, Pitgam, Cuvilly, Ourcq and Dierrey inter-

connection stations;• Flanders pipeline between Pitgam and Alve-

ringem;• Hondshoote metering station on the Belgian

border.

Ongoing projects

GRTgaz continues its work on confirmed projects, namely.

Arc de Dierrey is under construction on the Dierrey Voisines section.

Following the decision made by the CRE on 7 May 2014 to retain the ‘Val de Saône + Gascogne- Midi’ solution to create a single marketplace in France by 2018 and discussions on 25 September 2015 on the incentive regulation mechanism ap-plied to this solution. The decision to make these investments was made by GRTgaz.

In light of this strategy, the commissioning of Eri-dan was postponed until 2021/2022 in order to coincide with entry capacity development projects in the south of France. The Eridan project’s Dec-laration of public interest and Ministerial authori-sation for construction and operation were issued on 5 January 2015.

Furthermore, it was decided that 100 GWh of capacity from Switzerland towards France would be created at Oltingue.

Studies under way and projects pending a decision

Discussions with stakeholders have allowed us to confirm most of the projects identified in the pre-vious plan, although their implementation dates may have been pushed back:

• development of the Montoir and Fos-sur-Mer LNG terminals;

• development of the Manosque storage site;

• capacity increase between France and Spain to the east of the Pyrenees (Midcat project);

• creation of capacity from France towards Ger-many.

Projects on hold

Other projects were suspended by their promoters.

• Fos Faster put an end to its plans for a new LNG terminal at Fos-sur-Mer.

• Creos suspended its interconnection project with France.

3.2 project portfolio changes

_ 57


The CRE intends to pursue the simplification of the transmission market in France, while re-maining consistent with the projected organisation of the European gas market. It asked GRTgaz and TIGF to create a single marketplace in the south on 1 April 2015. The CRE’s goal is to establish a single marketplace in France by 2018 by merging the North and South Zones, and therefore recommends the execution of the Val de Saône and Gascogne-Midi projects.

Development of marketplaces in France

GRTgaz has consistently invested to reduce the number of balancing zones (from seven to three since 2003) and thereby facilitate the use of the network and the integration of the French net-work into the European system. The significant price spread between the North and South Zones and the outcome of the spring 2014 auction on the North-South link illustrate the physical con-gestion that exists between the northern and the southern parts of the GRTgaz network. The CRE and market players wish to continue their efforts to simplify the French market structure with a view to setting up a single marketplace in France, while remaining consistent with the projected or-ganisation of the European gas market.


The first stage of this process involves the creation of a shared PEG at the GRTgaz South and TIGF balancing zones. In response to the CRE’s request, the two French transmission operators took steps in order to launch this new marketplace on 1 April 2015. As of this date, capacity at the interconnec-tion between GRTgaz and TIGF is no longer mar-keted and shippers can no longer call for capacity on the PIR Midi point. GRTgaz and TIGF manage the physical interconnection with their consump-tion forecasts. The creation of Trading Region South has not required any additional physical changes to the network.

Creation of a single marketplace in France

In 2011, the study entrusted to KEMA demon-strated that the merger of the GRTgaz North and South market zones based on the Arc de Dierrey and Eridan projects would imply the need for con-tractual mechanisms that were potentially very expensive.

In 2012, GRTgaz considered an approach that would combine investments and contractual mechanisms. In addition to the Arc de Dierrey and Eridan projects, the Val de Saône project, which involves looping the Burgundy pipeline between Voisines (Yonne) and Etrez (Ain), stood out as the most efficient solution to ease congestion and limit the use of contractual tools. The CRE took this information into account when it declared it-self in favour of the creation of a single PEG based on the Val de Saône project, following discussions on 19 July 2012.

In accordance with these discussions, and to con-firm this strategy, the CRE asked the firm, Pöyry,

3.3 a single marketplace in france in 2018

Montoir-de-Bretagne

Dunkirk

Obergailbach

Oltingue

Fos

Taisnières

Pirineos

Transit zone

Zone lacking gas

South-East

Collectionzone

SUPPLY AND CONGESTION IN CASE OF LOW LNG DELIVERIES

58 _


to conduct a comparative cost-benefit analysis in the second half of 2013 on different investment solutions for the creation of a single PEG.

The analysis confirmed the validity of the Val de Saône project. It also identified a more eco-nomical alternative to the Eridan project given the creation of a single PEG: the undertaking of the Gascogne-Midi project, which would involve consolidation work on the GRTgaz and the TIGF networks.

Such consolidation works were mapped out to cover a series of flow configurations shared with the market, particularly the hypothesis of an entry flow at Dunkirk similar to the current subscription level. The natural gas offer at the single PEG will be capable of meeting the shippers’ usual require-ments, as envisaged in the Pöyry study. Exception-al systems will have to be put into place when the flow configurations depart from the initial assumptions.

The Pöyry study concluded that the creation of a single PEG would generate benefits for the French and Iberian markets under all market scenarios in which LNG is not less expensive for a long peri-od than gaseous gas delivered by pipeline. These benefits are even greater than the investment costs in the event LNG becomes more expensive than gaseous gas.

This scenario calls for large transmission capaci-ties from the North to the South, which led to the identification of the most efficient consolidation works to transmit large volumes of gas collected at interconnection points in the North towards the South.

This solution involves:

• looping the Burgundy pipeline between the Voisines and Etrez stations (Val de Saône pro-ject), which allows transit operations to be de-veloped in the east, the shortest route between

the collection zone in the north and the zone to be supplied in the south;

• strengthening the West-East route in the south (Gascogne-Midi project), which opens up the south-east by creating an additional supply line from the west.

Following the public consultation process under-taken in February and March 2014, the CRE con-firmed the decision to create a single marketplace by 2018 on 7 May 2014. It retained the invest-ment plan for the Val de Saône and Gascogne- Midi projects. On 25 September 2014, it defined the incentive regulation mechanisms applied to these two projects.

The Val de Saône project

The project involves looping the Burgundy pipe-line (ND 1200) over a distance of 189 km between Voisines and Etrez, and boosting the capacity of the compressor station at Etrez by installing a third 9 MW compressor, and adjusting the interconnec-tions at Etrez, Palleau and Voisines accordingly.

GRTgaz launched this project’s appraisal studies as early as July 2012. The public debate was held in the last quarter of 2013 and ended with a favour-able recommendation from the National public debate commission. The gas transmission authori-sation application was filed in July 2014. The pub-lic enquiry was held in the summer of 2015 and gave rise to a small number of remarks.

The CRE conducted an audit on the project’s tech-nical choices, costs and timelines in June 2014.

The preliminary studies estimated the cost of the project at around €740 million. The teAMS at GRTgaz and the project’s stakeholders are work-ing to ensure all of the project’s infrastructure is commissioned by 1 November 2018.

In October 2013, the Val de Saône project was recognised as a ‘Project of common interest’ (PCI) by

_ 59


the European Commission. The French and Spa-nish regulators decided to allocate the cost of the project to the French market alone. In order to re-lieve the burden of this investment on French users, the project was awarded funding capped at €74 m by the European Union. The final investment deci-sion was made by GRTgaz on 7 September 2015.

This project was recognised as a PCI by the Euro-pean Union in 2013.

The Gascogne-Midi project

The project will supply the PACA (Provence, Alps and Côte d’Azur) region in the south-east of France by creating a backhaul flow from TIGF to GRTgaz through the Midi pipeline.

• On the TIGF network, the project entails the partial looping of the Gascogne pipeline over a distance of 60 km between Lussagnet and Barran and alterations to the Barbaira station.

• On the GRTgaz network, the Cruzy (Hérault) and Saint-Martin-de-Crau (Bouches du Rhône) stations will be adapted to operate the Midi pipeline in a backhaul direction.

The provisional budget is €152 million for TIGF and €21 million for GRTgaz; commissioning is scheduled for 2018.

This project is a PCI candidate.

Voisines

CruzyBarbaira

Palleau

Etrez

Saint-Martin-de-Crau

Val d

e Sa

ône

Gascogne pipelineMidi pipeline

Gascogne Midi


LNG terminal

In progress

In the north, the French network imports gas from Norway at Dunkirk and has entry capacity for H-gas and for L-gas from Belgium at Taisnières. In 2015, a new LNG terminal shall be commissioned at Dunkirk and a new exit point towards Belgium shall be created at Alveringem to boost the inte-gration of the French, Belgian and north European markets. The Arc-de-Dierrey core network project will accommodate this new terminal’s capacity and streamline the circulation of gas in the North Zone.

Connecting the new Dunkirk terminal (2015)

With a capacity of 13 bcm/year, this terminal should be operational by the end of 2015. Its connection to the network requires the following work:

• the creation of a 900 mm-diameter linking pipe-line over a distance of 17 km between the termi-nal and the Pitgam compressor station (North); this pipeline will carry non-odorised gas;

3.4 developments in the north zone

CREATION OF A SINGLE MARKETPLACE IN FRANCE

60 _


• the looping of the Hauts-de-France pipeline be-tween Nédon (Pas-de-Calais) and Cuvilly (Oise) with a 1,200 mm-diameter pipeline over a dis-tance of 123 km and alterations to the intercon-nection stations of Pitgam, Cuvilly, Ourcq and Dierrey (Aube);

• the creation of the first section of the Arc de Dier- rey over a distance of 180 km between Cuvilly and Dierrey; the commissioning of a second sec-tion between Dierrey and Voisines in late 2016.

This infrastructure will increase entry capacity from the Dunkirk zone towards PEG North and Belgium via the new Network Interconnection Point at Alveringem by 520 GWh/d.

Except for the transmission line between Dierrey and Voisines, which is in the process of being built, all of the infrastructure will be commis-sioned before the end of 2015 so that the Dunkirk LNG terminal may be launched on to the market.

The decision in favour of this connection work was taken on 30 December 2011. The investment approved by the CRE totals €1,185 million. The core-network developments associated with this project (Arc de Dierrey) and the increase in entry

capacity at Taisnières H (commissioned in 2013) were awarded €104 million in funding by the European Union under the European energy pro-gramme for recovery.

The Arc-de-Dierrey project was identified in 2013 as a PCI by the European Union and is not a can-didate for the renewal of this label.

Belgium: creating exit capacity at Alveringem (2015)

Before the construction of the new LNG terminal at Dunkirk, GRTgaz was unable to export gas to Belgium. In France and Spain, gas odorisation, which is mandatory on distribution system to iden-tify leaks, is carried out centrally at the transmis-sion network’s entry point, while in most Europe-an countries, including Belgium and Germany, it is carried outjust upstream the distribution network.

GRTgaz does not, therefore, sell firm exit capacity towards this country.

The new Dunkirk LNG terminal, by bringing non-odorised gas close to the Belgian border, will allow firm capacity to be sold from France towards Belgium. A new interconnection point, dedicated to non-odorised gas, will be created close to Al-veringem.

In 2010, GRTgaz and Fluxys launched a joint mar-ket consultation process to assess requirements. The outcome of the non-binding phase led them to offer the following for the binding phase:

• at Alveringem, exit capacity from the GRTgaz network and entry capacity on the Fluxys net-work allocated in a coordinated fashion and marketed by GRTgaz and Fluxys, respectively;

• at the Dunkirk terminal, entry capacity on the Fluxys network, marketed by Fluxys thanks to a transmission service contract with GRTgaz.

The consultation phase ended in 2012 with a decision to allocate 100 GWh/d in firm capacity from PEG North towards Belgium over the first two years and 166 to 219 GWh/d in firm capacity from the terminal towards Belgium depending on the year in question.

TIGF

Voisines

Dierrey

Ourcq

Cuvilly

PitgamDunkirk

Alveringem

Taisnières

Obergailbach

Oltingue


Montoir-de-Bretagne

Hauts de France II

Arc de Dierrey


LNG terminal

In progress

CONNECTION OF THE DUNKIRK LNG TERMINAL AND CREATION OF EXIT CAPACITY TOWARDS BELGIUM

_ 61


On the French side, the completion of this new interconnection required:

• modifications to the Pitgam interconnection;

• the creation of the Flanders pipeline, approximately 25 km in length, to transmit non- odorised gas between the Pitgam station and the Alveringem interconnection point.

In Belgium, Fluxys built a 75 km pipeline between Alveringem and Maldegem.

GRTgaz has invested approximately €86 m.

This infrastructure will be commissioned in No-vember 2015.

This project was recognised as a PCI by the Euro-pean Union in 2013.

Switzerland / Italy: creating entry capacity at Oltingue (2018)

This South-North capacity development project between Italy, Switzerland and France is being carried out in close cooperation with the adja-cent operators. It had been under consideration for several years and regularly requested by ship-pers since 2010. In 2010, FluxSwiss launched a market consultation process to assess the de-mand for transmission capacity from Italy to-wards France, which resulted in the booking of capacity. At the beginning of 2015, it decided to make the investments necessary. For its part, Snam Rete Gas decided to invest in its transmis-sion network so as to be able to export more than 400 GWh/d towards Switzerland to supply France and Germany.

In order to improve the connection between the French and Italian markets, GRTgaz decided in 2015, with the support of market players and the regulator, to make the investments necessary to permit backhaul flows and create an entry capacity of 100 GWh/d, which may be increased to 200 GWh/d.

The work consists of the alteration of Oltingue station, which is the interconnection point with Switzerland, and of Morelmaison station so as to

reverse the direction of the gas flow on this sec-tion at a cost of around €15 m.

Capacity should be made available in 2018, at a time when exit capacity towards Italy and transit capacity via Switzerland are delivered.

By creating a new entry point in France, this pro-ject provides access to new sources of gas from Libya, Algeria (by pipeline) and Azerbaijan. The Trans Adriatic Pipeline (TAP) will supply 10 bcm of Azeri gas to Italy in 2019/2020; this project lends weight to the creation of backhaul capacity from Italy to France.

This project also connects the PEG North and PSV marketplaces in both directions, thereby creating new trading opportunities between these markets.

This project was identified as a PCI by the Euro-pean Union in 2013 and is a candidate for the renewal of this label.

Germany: creating exit capacity at Obergailbach (2022)

As part of the reinforcement of the North-South Corridor in the west of Europe, GRTgaz is study-ing the creation of 100 GWh/d in firm exit capacity towards Germany at Obergailbach. This could fulfil the need for natural gas entries in western Germany, as identified in the German develop-ment plan regarding the replacement of L-gas.

To create this capacity, the following work is en-visaged:

• the looping of all or part of the North-East pipe-line between Morelmaison (Vosges) and Voisines;

• the restructuring of interconnection points at Voisines, Morelmaison and, if necessary, Ober-gailbach;

• the installation of a compressor station at Chep-py (Meuse);

• an increase in compression at Voisines and Dierrey.

In the absence of a clear request from German market operators and due to the time required to build the above-mentioned infrastructure, the project was postponed from 2021 to 2022.

62 _


The creation of exit capacity towards Germany also depends on the harmonisation of odorisation practices between France and Germany.

As explained previously, France cannot export odorised gas towards Germany as German trans-mission operators do not accept it, except in the case of force majeure. This question is considered under the Network Code on Interoperability, ap-proved by ACER and the European Commission. The Code states that if different practices hinder cross-border trade, operators will have to reach an agreement to remove the barriers to such trade. If no agreement is reached, the non-odorisation of gas will be the solution retained.

The purpose of the Odicee project is to clarify this problem. The solution that is currently being con-sidered is the decentralisation of gas odorisation on the GRTgaz network. In order to assess the safety, reliability and cost of the technical solutions envisaged, GRTgaz launched a pilot project, which is still in progress, in 2015 on two sites, Etroeungt (North) and Bas Lieu (North). These stations add, at the distribution network’s entry point, odour to a gas that has already been odorised. The results

will be used to assess the conditions under which this process would be rolled out on the national network. Prior to this experiment, the investment necessary to decentralise odorisation and create exit capacity towards Germany had been put at approximately €600 million at the project identi-fication stage.

In addition to this experiment, GRTgaz is also ex-ploring alternative solutions, such as the instal-lation of a deodorisation unit on the North-East pipeline.

This project (creation of capacity from France to-wards Germany, including the harmonisation of odorisation practices) was identified as a PCI in 2013 by the European Union and is a candidate for the renewal of this label.

Luxembourg: increasing exit capacity

To respond to the expected growth of Luxem-bourgian consumption and to meet requirements laid down in security of supply regulations, Creos Luxembourg asked GRTgaz to examine the laying of a pipeline between the Lorraine pipeline and Luxembourg, which would have increased transit capacity from France. The investment was esti-mated at €72 million in 2012 for an exit capacity of 40 GWh/d.

The two operators launched a joint market consultation process, which was completed in May 2013. However, there was no confirmed in-terest for the capacity put forward.

As Luxembourg was moving towards the Belgian market to create the BeLux market on 1 October 2015, CREOS decided to abandon this project in September 2015.

Supporting the development of the Montoir terminal (2021)

Elengy plans to increase the capacity of the LNG terminal of Montoir-de-Bretagne from 10 bcm to 16.5 bcm in 2021. A market consultation process (non-binding phase) is in progress.

Single market France

TIGF

Voisines

Dierrey

Cheppy

Morelmaison

Dunkirk Alveringem

Taisnières

Obergailbach

Oltingue


Montoir-de-Bretagne

Pirineos

North-Ea

st pipeli

ne


LNG terminal

In progress

Under consideration

DEVELOPMENT OF INTERCONNECTIONS WITH GERMANY AND ITALY

_ 63


In order to accommodate this capacity, the Auvers-le-Hamon compressor station would have to be adapted, the Maine pipeline would have to be looped with a 1050-ND pipeline between No-zay (Loire-Atlantique) and Cherré (Maine et Loire),

and a pipeline would have to be installed between Chémery (Loir-et-Cher) and Dierrey.

Maintaining supply for L-gas consumers

The L-gas supplied to the GRTgaz network comes from the Groningue deposit in the Netherlands. This deposit has now entered a phase of rapid depletion and its exploitation could cause earth-quakes. The Dutch government announced in early 2014 that export contracts would not be renewed. GRTgaz must therefore be prepared for a gradual fall in its L-gas supply from 2024 and a complete halt in 2029, at the latest.

The number of customers currently supplied in L-gas is 1.3 million. The conversion of this zone to H-gas could take place between 2021 and 2029. Research on the implementation of this conver-sion process is being conducted in conjunction with GrDF and Storengy, under the auspices of the public authorities. At this stage, the adapta-tion of each consumer’s installation is envisaged. GrDF would undertake the conversion work by geographical area. During the conversion period, GRTgaz would adapt its network to guarantee the transmission of both L-gas and H-gas.

Trading Region South, operated by GRTgaz and TIGF, is supplied by the Fos Tonkin and Fos Cavaou LNG terminals at Fos-sur-Mer and has interconnection ca-pacity with the North Zone of GRTgaz at the North-South link, and with Spain through the TIGF network at the virtual interconnection point, PIRINEOS.

The Val de Saône and Gascogne-Midi infrastruc-ture development project will significantly increase the flow of gas from the North to the South as from 2018, thereby permitting the creation of a single marketplace in France.

In the opposite direction, however, the network’s ability to accommodate significant additional flows in the south is restricted by the limited ca-pacity of the Saint-Martin-de-Crau – Etrez pipe-line. Any project that aims to increase capacity in the south of the South Zone would therefore require, depending on the project’s needs, all or part of this pipeline to be strengthened, including and first of all, the looping of the Rhône pipeline.

3.5 developments in the south zone


Dierrey

ChémeryMontoir-de-Bretagne

Dunkirk Alveringem

Taisnières

Obergailbach

Oltingue

Cherré

Nozay

Auvers-le-Hamon


TIGF

Maine pipeline


LNG terminal

In progress

Under consideration

DEVELOPMENT OF REGASIFICATION CAPACITY AT MONTOIR DE BRETAGNE

64 _


The Eridan project: looping of the Rhône pipeline

The Eridan project will loop the Rhône pipeline by building a 220 km pipeline between the inter-connection stations of Saint-Martin-de-Crau and Saint-Avit (Drôme), which will be adapted, and close to the Tersanne storage facility.

This infrastructure, which was decided in 2011 and is scheduled to be commissioned in 2016, aims to boost the capacity of LNG delivered at the LNG terminals at Fos and transmitted to the North, to facilitate the merger of the GRTgaz North and South Zones and to increase intra-day flexibility in the south of the South Zone. The in-vestment, estimated at €484 m, was approved by CRE. The cost of the project is now estimated at €620 m, following detailed studies and a public discussion in 2013.

Following CRE discussions on 7 May 2014, the project is no longer retained for the merger of the North and South Zones. However, it is necessary for any project requiring the development of the North-South Corridor, such as the development of capacity from Spain (Midcat project) or from the Fos LNG terminals. On 27 October 2014, the pro-ject was declared to be in the public interest and GRTgaz received ministerial authorisation to con-struct and operate the pipeline on 5 January 2015.

Once the requirements have been confirmed, Eri-dan may be completed within five years.


Supporting future increases in capacity: the Arc Lyonnais project

The Arc Lyonnais project consists of looping the pipeline between Saint-Avit and Etrez to support capacity increases in the south of the South Zone superior to the capacity served by the Eridan pro-ject (around 120 GWh/d). These requirements could be met by undertaking one major project or several development projects from among the following: new LNG regasification capacity at Fos, new withdrawal capacity at the Manosque stor-

age facility, new interconnection capacity with Spain (Midcat project).

Public discussions on this project were held in con-junction with those of the Val de Saône project at the end of 2013. The preliminary studies will be carried out as soon as the project schedule for the commissioning of the works is clearer.


Supporting the development of the Manosque storage facility (2019 and 2020)

Géométhane plans to renovate the Manosque storage facility (Alpes-de-Haute-Provence) and to increase its injection capacity in 2019 and its with-drawal capacity in 2020.

Increasing the withdrawal capacity of this storage site could require:

• alterations to the interconnection stations at Saint-Martin-de-Crau and Etrez;

• the boosting of compression at Saint-Martin-de-Crau.

Supporting the development of the Fos Cavaou terminal (2021)

Fosmax LNG plans to increase the capacity of the Fos Cavaou terminal up to 16.5 bcm by 2021. Fol-lowing a public consultation process in the spring of 2013, Fosmax LNG is still studying its project. This development could require:

• adaptations to the Saint-Martin-de-Crau inter-connection point;

• the looping of the Rhône pipeline between Saint-Martin-de-Crau and Saint-Avit (Eridan project)

• the looping of Est Lyonnais;

• depending on the project’s requirements, in-creased compression at Saint-Martin-de-Crau (Bouches-du-Rhône), Saint-Avit and Palleau;

• the completion of the looping of the Beauce pipe-line via the Perche pipeline over a distance of 63 km between Cherré and Saint-Arnoult-des-Bois.


_ 65


Elengy no longer mentions the development plan of the Fos Tonkin LNG terminal, whose capacity remains at 3 bcm per year.

TIGF and Spain

• Increasing capacity (2013 and 2015)

Following consultations undertaken in 2009 and 2010, interconnection capacity between France and Spain was boosted in both directions.

In 2013, capacity at Port de Larrau rose from 110 to 165 GWh/d in the direction, Spain to France, and from 100 to 176 GWh/d in the direction, France to Spain, thanks in particular to the commissioning of a new compressor station at Chazelles. This project received €48 m in funding from the European Union and a budget of €99 m approved by the CRE.

In 2015, capacity increased from 5 to 60 GWh/d in the direction, Spain to France, at Biriatou. In the direction, France to Spain, new interruptible capacity is also available.

These developments will increase the Spain-France interconnection rate to 27% of Spanish consump-tion.

On 4 March 2015, at a summit on electricity and gas interconnections in Madrid between Por-tugal, Spain and France, these three countries agreed to study the strengthening of connec-tions between the Iberian Peninsula and Europe’s energy markets. A high-level group was there-fore formed for this purpose under the aegis of the European Commission and the competent French, Portuguese and Spanish authorities. In parallel, in 2015, the European Commission launched a study on the benefits, cost and fea-sibility of new interconnection points; the study’s findings for gas are expected to be released in December 2015.

• Creating an interconnection point to the east of the Pyrenees (2022)

The Midcat project (Midi-Catalonia) would deve-lop the North-South corridor by creating a new interconnection point to the east of the Pyrenees. This project is part of the Ten Year Network Deve- lopment Plan (TYNDP) carried out by ENTSOG and part of the joint regional investment programme of Portugal, Spain and France (GRIP South).

It would create an additional capacity of 230 GWh/d in the direction, Spain to France, and 80 GWh/d in the direction, France to Spain. To make this possible, the following work on the GRTgaz network would have to be considered:

- the looping of the Rhône pipeline between Saint-Martin-de-Crau and Saint-Avit (Eridan project);

- the looping of the Arc Lyonnais;

- if necessary, expansion of the compressor sta-tions located between Saint-Martin-de-Crau and Voisines;

- the creation of a new compressor station at Montpellier (Hérault);

- the completion of the looping of the Beauce pipeline via the Perche pipeline over a distance of 63 km between Cherré and Saint-Arnoult-des-Bois.

This project was identified in 2013 as a PCI by the European Union and is a candidate for the renew-al of this label.


TIGF

St-Arnoult-des-Bois

Cherré

Palleau

Etrez

Saint-Avit

Saint-Martin-de-CrauMontpellier

Montoir-de-Bretagne

Pirineos

Perch

e pipeli

ne

Lyon

nais

pip

elin

e

Erid

an


LNG terminal

In progress

In study phase

Under consideration

DEVELOPMENT OF INTERCONNECTION POINTS WITH SPAIN AND REGASIFICATION AT FOS-SUR-MER

66 _


Development projects related to storage facilities

In the light of the very poor economic climate, Storengy decided to put all of its development projects in the North and South Zones on hold, in-cluding the commissioning of Hauterives (Drôme). The only envisaged change is the connection of an additional cavity in Etrez, without reinforce-ment of the network identified at this stage.

Permitting the injection of biomethane into the natural gas network

According to ADEME, between 12 and 30 TWh of biomethane could be injected into the networks by 2030. It would require the construction of 500 to 1,400 injection sites, around 15% of which would be built on the GRTgaz network.

To date, GRTgaz has signed 16 study agreements. As from 2016, between three and five projects should be confirmed each year.

For the producer, an injection site on the transmis-sion network comprises a methanisation, treatment and compression unit. GRTgaz then connects the producer to the regional network through a spur pipeline and an injection station that has the fol-lowing main functions: monitoring of the characteristics of the gas, metering and odorisation.

In the event the production of injected biome-thane exceeds the network’s local consumption (GRTgaz distribution, regional coverage), the equipment (compression, control valve, etc.) that allows the bi-directional circulation of flows on the gas networks would have to be adapted and installed locally to permit a ‘backhaul’ that would return surplus gas to the network upstream of the usual flow. This function would maximise the injection of biomethane into the distribution sys-tem. One or two installations of this kind could be built over the plan’s lifetime. Currently, ‘backhaul’ from the GRTgaz regional network to the main transmission network is not authorised due to constraints imposed on storage installations.

Permitting the production of electricity with natural gas

According to RTE forecasts (updated in 2015), no gas-fired power plants, except for the Bouchain and Landivisiau plants, will be built in 2020. The only network development project planned for this period and associated with the connection of these new plants is the strengthening of the regional network in the south of Brittany (111 km between Pleyben and Plumergat).

For 2030, regarding New Mix and Diversification scenarios, RTE foresaw in 2014 the construction of new Combined Cycle Plants (around 4 GW) and new Combustion Turbine Generators (around 2 GW) (while considering that half of the peak re-quirements identified would be met through ad-ditional load shedding and half by new types of gas-fired CTGs).

These hypotheses indicate that, overall, the num-ber of plants connected to the gas network in 2030 will be double the number it is today. Com-pared to the gas network in the UK and Italy, for example, this volume remains modest. Guaran-teeing continuity of supply for these new facili-ties should not bring about major changes to the network. Nevertheless, depending on the location and size of the future Combined Cycle Plant/CTG projects, it may be necessary to strengthen the re-gional network.

Depending on how the new facilities are used (semi-base and peak production during the day or production that complements intermittent supplies from renewables), the volume of gas consumed by these plants may vary significantly throughout the day. Intra-day flexibility developed on the network following the recent implementa-tion of infrastructure shall fully or partly respond to these changes in consumption. Nevertheless, this subject will have to be assessed in more detail with the electricity transport network operator in light of the hypotheses retained following the ap-plication of the ‘law on energy transition for green growth’ (LTECV).

3.6 other development projects

_ 67


All infrastructure to be commissioned between 2015 and 2017 was approved and scheduled in the GRTgaz financing plan. The Board of Directors has approved the budget for its completion. These

facilities, linked to the connection of the Dunkirk LNG terminal and the development of capacity with Belgium, are described hereafter:

3.7 infrastructure to be commissioned over the next three years (2015 - 2017)

The Val de Saône and Gascogne-Midi projects, necessary for the merger of the North and South Zones of GRTgaz and the creation of a single trad-ing point in France, were approved by the regu-lator on 7 May 2014. The Val de Saône project was given the go-ahead on 7 September 2015 by GRTgaz.

The creation of entry capacity at Oltingue was ap-proved by the CRE on 17 December 2014 and was given the go-ahead by GRTgaz on 24 July 2015.

The decision to proceed with the other projects will be taken when:• market interest has been confirmed;• the decision on the completion of adjacent in-

frastructure, if applicable, has been taken;• financing is secured;• the investment has been approved by the CRE.

To establish the schedule of works to be completed, GRTgaz takes into account the information provided by the operators of adjacent infrastruc-ture regarding the capacity to be developed and the commissioning dates sought. The infrastruc-ture to be built or adapted, in particular for the core network, depends on the order of arrival and the extent of the requirements for an increase in entry or exit capacity in the relevant market zone. The facilities indicated below will be reviewed if the demand-for-capacity schedule is modified.

Given this uncertainty, only preliminary design studies have been conducted for the most distant deadlines. More in-depth analyses will complete the initial studies once requirements have been clarified, at which time a need to adapt other fa-cilities may be identified.

3.8 infrastructure commissioned after 2017

Capacity demand spurring consolidation

Infrastructure to be adapted or built Commissioning

Decision status

Connection of the Dunkirk LNG terminal

• Clipon pipeline (19 km, ND 900)

• Looping of the Hauts-de-France pipeline from Nédon to Cuvilly (123 km, ND 1200)

• Arc de Dierrey between Cuvilly and Dierrey (180 km, ND 1200)

• Adaptation of the Pitgam, Cuvilly and Dierrey interconnections, and creation of the Ourcq interconnection

2015 In progress

Create exit capacity towards Belgium • Flanders pipeline 2015

In progress

Fluidity of the North Zone following the increase in capacity at Dunkirk and Taisnières H

• Arc de Dierrey between Dierrey and Voisines (120 km, ND 1200)

• Adaptation of the Voisines interconnection

2016 In progress

68 _


Capacity demand spurring consolidation

Infrastructure to be adapted or built

Commis-sioning

Decision status

Increase entry capacity from Switzerland

• Adaptation of the Oltingue and Morelmaison interconnection stations

2018 Decided

Merge Zones Val de Saône project:• Looping of the Burgundy pipeline between Voisines and Etrez

(186 km, ND 1200)• Adaptation of the Voisines, Palleau and Etrez interconnection

stations• Increase in compression at Etrez (+ 9 MW)

Gascogne-Midi project:• Adaptation of the Cruzy and Saint-Martin-de-Crau stations

2018 Decided

Increase entry capacity from the storage facilities at Manosque

• Adaptation of the Saint-Martin-de-Crau interconnection point• If applicable, increase in compression at Saint-Martin-de-Crau

2019/2020 Waiting for the promoter’s decision

Extend the Fos Cavaou LNG terminal

• Eridan: looping of the Rhône pipeline, (220 km, ND 1200) and adaptation of the Saint-Avit and Saint-Martin-de-Crau interconnections points

• If applicable, looping of the Arc Lyonnais and adaptation of the compressor stations at Saint-Avit and Etrez

• Reinforcement of the Saint-Martin-de-Crau compressor station• If applicable, reinforcement of the Saint-Avit and Palleau compressor

stations• If applicable, completion of the looping of the Beauce pipeline via

the Perche pipeline over a distance of 63 km between Cherré and Saint-Arnoult-des-Bois

2021 Waiting for the promoter’s decision

Increase entry capacity from the Montoir terminal (+ 4 bcm/year)

• Adaptation of the compressor station at Auvers-le-Hamon• Looping of the Maine pipeline and reinforcement of the Cherré

compressor station, if applicable• If applicable, creation of a pipeline between Chémery and Dierrey

2021 Waiting for the promoter’s decision

Increase interconnection capacity between France and Spain

• Eridan: looping of the Rhône pipeline, (220 km, ND 1200) and adaptation of the Saint-Avit and Saint-Martin-de-Crau interconnections points

• If applicable, looping of the Arc Lyonnais and adaptation of the compressor stations at Saint-Avit and Etrez

• Reinforcement of the Saint-Martin-de-Crau compressor station• If applicable, reinforcement of the Saint-Avit and Palleau compressor

stations• If applicable, completion of the looping of the Beauce pipeline via

the Perche pipeline over a distance of 63 km between Cherré and Saint-Arnoult-des-Bois

• Creation of a compressor station in Montpellier

2022 Under discussion: go-ahead based on benefits generated for Europe

Create exit capacity towards Germany

• Installation of a deodorisation unit on the North-East pipeline or decentralised odorisation (Odicée project)

• If applicable, adaptation of the Obergailbach interconnection point• Looping of the Morelmaison–Voisines pipeline• Adaptation of the Morelmaison and Voisines interconnection points• If applicable, a new compressor station at Cheppy• If applicable, increase in compression at Dierrey

2022 Pilot project in progress

_ 69


3.9 forecast capacity development for 2015-2024

As on 1 January in GWh/d 2015 2016 2017 2018 Beyond (1)

NORTH ZONE

Entry capacity 2,660 3,180 3,180 3,180

Norway - Dunkirk PIR 570 570 570 570 570

Belgium - Taisnières H PIR 640 640 640 640 640

Belgium - Taisnières L PIR 230 230 230 230 230

Germany - Obergailbach PIR 620 620 620 620 620

Switzerland/Italy - Oltingue PIR 100 (2)

LNG - Montoir PITM 370 370 370 370 420 - 550

LNG - Dunkirk(Dunkirk PITM towards North Zone and Dunkirk towards Belgium)

520 520 520 520

South Zone to North Zone 230 230 230 230 Merger (3)

Exit capacity 530 800 800 800

Switzerland/Italy - Oltingue PIR 223 223 223 223 223

Switzerland - Jura PIR 37 37 37 37 37

Belgium - (Alveringem PIR and Dunkirk towards Belgium)

270 270 270 270

Germany - Obergailbach PIR 100

North Zone to South Zone 270 270 270 270 Merger (3)

SOUTH ZONE

Entry capacity 935 680 680 680

LNG - Fos PITM 410 410 410 410 700 - 1,160

TIGF (Midi PIR) towards South Zone 255 (4)

North Zone to South Zone 270 270 270 270 Merger (3)

Exit capacity 625 230 230 230

Towards TIGF (Midi PIR) from South Zone

395 (4)

South Zone to North Zone 230 230 230 230 Merger (3)

1. Capacity could be reassessed after the zones are merged.2. Type of capacity to be defined in accordance with the capacity offered at Obergailbach.3. In practice, the infrastructure planned as part of the merger will not create any South-to-North capacity. However, the analysis of the flows forecast on the network for this period as part of the merger studies does not identify any scenarios with significant South-to-North flows which would exceed the network’s current capacity in this direction.4. Creation of a TIGF - GRTgaz South trading region on 01/04/2015.

70 _


The French gas system benefits from a level of flexibility and resilience that guarantees the coun-try’s continuity of supply, including during cold peaks, in compliance with the constraints defined at European level by regulation 994/2010 regarding security of supply and public service obliga-tions enshrined in French law.

In order to comply with obligations regarding the coverage of cold peaks, various additional analy-ses and tests are carried out by GRTgaz and ENT-SOG on different geographic and time scales.

For the short term, every year at the start of win-ter, GRTgaz analyses coverage of peak demand and of the gas balance, more generally, in ac-cordance with storage site levels, the severity of the winter and the latest import trends. ENTSOG carries out a similar analysis at a European level through the Winter Supply Outlook.

For the year, 2024, the P2 firm point is estimated at a maximum of 4,476 GWh/d (4,126 GWh/d on the GRTgaz network in 2014 under the ‘Di-versified Uses’ scenario and 350 GWh/d on the TIGF network). Possible transit flows of up to 695 GWh/d towards Switzerland, Spain and Bel-gium must also be added.

At this time and including the projects that have been decided, total firm entry capacity will rise to 3,615 GWh/d. Assuming that the replenishment of the storage sites is equivalent to that of the winter of 2015/2016, the network has a margin of more than 20% of peak demand. The country’s gas infrastructure therefore offers enough flexibility to cover peak demand. Nevertheless, security of supply will depend on the actions of suppliers, which are responsible on a daily basis for balancing their client portfolio over the winter and at the time of peak demand. In light of this, Euro-pean and national regulations must ensure that the market provides a satisfactory level of security.

Over the longer-term and on a European level, ENTSOG assesses every two years in the TYNDP the adequacy between supply, demand and Eu-

ropean infrastructure. This assessment considers crisis scenarios such as peak demand or the loss of a supply source or route. The 2015 report il-lustrates the French network’s ability to respond to such scenarios. The report’s findings corrobo-rate the risk analyses conducted by GRTgaz and France as part of the implementation of regula-tion 994/2010.

Regarding infrastructure

This subject is covered by criterion N-1 in regula-tion 994/2010. This indicator measures the capacity that is available to cover peak demand in the event the main infrastructure fails:

N-1 2015 2025 2035

Existing and decided infrastructure 100 -

120%

>120% >120%

With other projects

>120% >120%

The commissioning of the Dunkirk LNG terminal and of the second stage of development with Spain will allow France to significantly increase its margin of resilience in light of regulation 994/2010.

Regarding availability of supply

This subject is covered by the ‘Remaining Flexibil-ity’ indicator, which measures the availability of gas at the time of peak demand with or without the loss of a supply route in Europe.

Remaining Flexibility ex-cluding loss 2015 2025 2035

Existing and decided infrastructure >20%

>20% >20%

With other projects

>20% >20%

3.10 meeting of demand for gas in france in 2024

APPENDIX

4

Appendix 1

Interconnection points: subscription and utilisation rates

Appendix 2

Determination of the network’s commercial capacity

Appendix 3

Execution of major projects

_ 71

72 _

APPENDIX

Midi PIR TIGF/Spain

Taisnières H and L from Belgium

Dunkirk from Norway Obergailbach from Germany

APPENDIX 1 interconnection points: subscription and utilisation rates

FROM TIGF

700

600

500

400

300

200

100

0

Jan. 2

009

May 20

09Se

pt. 20

09Jan

. 201

0May

2010

Sept.

2010

Jan. 2

011

May 20

11Se

pt. 20

11Jan

. 201

2May

2012

Sept.

2012

Jan. 2

013

May 20

13Se

pt. 20

13Jan

. 201

4

Jan. 2

015

May 20

14Se

pt. 20

14

Subscriptions Available Share reserved for the short termTechnical capacity

GWh/d

TOWARDS TIGF

700

600

500

400

300

200

100

0

Jan.

2009

Apr. 2

009

July

2009

Oct. 2

009

Jan.

2010

Apr. 2

010

July

2010

Oct. 2

010

Jan.

2011

Apr. 2

011

July

2011

Oct. 2

011

Jan.

2012

Apr. 2

012

July

2012

Oct. 2

012

Jan.

2013

Apr. 2

013

July

2013

Oct. 2

013

Jan.

2014

Apr. 2

014

July

2014

Oct. 2

014

Jan.

2015


GWh/d


TAISNIÈRE H

700

600

500

400

300

200

100

0

Jan. 2

011

Sept.

2011

May 20

12Jan

. 201

3May

2014

Jan. 2

015

Sept.

2015

Sept.

2013

May 20

16Jan

. 201

7Se

pt. 20

17May

2018

Jan. 2

019

Sept.

2019

May 20

20Jan

. 202

1Se

pt. 20

21May

2022

Jan. 2

023

Sept.

2023

May 20

24

GWh/d


TAISNIÈRE B

Jan. 2

011

Oct. 20

11Jul

y 201

2Apr.

2013

Jan. 2

014

Oct. 20

14Jul

y 201

5Apr.

2016

Jan. 2

017

Oct. 20

17Jul

y 201

8Apr.

2019

Jan. 2

020

Oct. 20

20

Jan. 2

023

Oct. 20

23

July 2

021

Apr. 20

22

700

600

500

400

300

200

100

0

GWh/d


700

600

500

400

300

200

100

0

Jan. 2

011

Sept.

2011

May 20

12Jan

. 201

3Se

pt. 20

13May

2014

Jan. 2

015

Sept.

2015

May 20

16Jan

. 201

7Se

pt. 20

17May

2018

Jan. 2

019

Sept.

2019

Sept.

2021

May 20

20

May 20

22

Jan. 2

021

Sept.

2023

May 20

24

Jan. 2

023

GWh/d


700

600

500

400

300

200

100

0

Jan. 2

011

Jan. 2

012

Jan. 2

013

Jan. 2

014

Jan. 2

015

Jan. 2

016

Jan. 2

017

Jan. 2

018

Jan. 2

019

Jan. 2

020

Jan. 2

021

Jan. 2

022

Jan. 2

023

Jan. 2

024

GWh/d

_ 73

APPENDIX

Oltingue towards Switzerland and Italy


Jan. 2

011

Aug. 2

011

Aug. 2

018

March 2

012

March 2

019

Oct. 20

12

Oct. 20

19

May 20

13Dec

. 201

3Jul

y 201

4Fe

b. 20

15Se

pt. 20

15Apr.

2016

Nov. 2

016

June 2

017

May 20

20Dec

. 202

0Jul

y 202

1Fe

b. 20

22Se

pt. 20

22Apr.

2023

Nov. 2

023

June 2

024

Jan. 2

018

700

600

500

400

300

200

100

0

GWh/d

North-South link


TOWARDS THE SOUTH

700

600

500

400

300

200

100

0

Jan. 2

011

July 2

011

Jan. 2

012

July 2

012

Jan. 2

013

July 2

013

Jan. 2

014

July 2

014

Jan. 2

015

July 2

015

Jan. 2

016

July 2

016

Jan. 2

017

July 2

017

Jan. 2

018

July 2

018

GWh/d


TOWARDS THE NORTH

700

600

500

400

300

200

100

0

Jan. 2

011

July 2

011

Jan. 2

012

July 2

012

Jan. 2

013

July 2

013

Jan. 2

014

July 2

014

Jan. 2

015

July 2

015

Jan. 2

016

July 2

016

Jan. 2

017

July 2

017

Jan. 2

018

July 2

018

GWh/jGWh/d

Storage sites

South-Atlantic interruptibleNorth-Atlantic interruptibleSouth-East

South-Atlantic �rmNorth-WestNorth-East

North-Atlantic �rmNorth L

INJECTION

2,500

2,000

1,500

1,000

500

0

July 2

012

Sept.

2012

Nov. 2

012

Jan. 2

013

March 2

013

May 20

13Jul

y 201

3Se

pt. 20

13Nov

. 201

3Jan

. 201

4Marc

h 201

4May

2014

July 2

014

Sept.

2014

Nov. 2

014

Jan. 2

015

March 2

015

Jan. 2

016

March 2

016

May 20

15Jul

y 201

5Se

pt. 20

15Nov

. 201

5

GWh/d

South-Atlantic interruptibleNorth-Atlantic interruptibleSouth-East

South-Atlantic �rmNorth-WestNorth-East

North-Atlantic �rmNorth L

WITHDRAWAL

2,500

2,000

1,500

1,000

500

0

GWh/d

July 2

012

Sept.

2012

Nov. 2

012

Jan. 2

013

March 2

013

May 20

13Jul

y 201

3Se

pt. 20

13Nov

. 201

3Jan

. 201

4Marc

h 201

4May

2014

July 2

014

Sept.

2014

Nov. 2

014

Jan. 2

015

March 2

015

Jan. 2

016

March 2

016

May 20

15Jul

y 201

5Se

pt. 20

15Nov

. 201

5

74 _

APPENDIX

GRTgaz markets gas transmission in the form of:

• firm capacity whose utilisation is guaranteed in a contract with the shipper under normal network operating conditions for the subscription period;

• interruptible capacity, the utilisation of which is not guaranteed.

If all the firm and interruptible capacity that GRTgaz offers is used, the system becomes saturated. Any increase in the transmission capacity of the GRTgaz network therefore requires additional investment.

Method used to determine capacity

The capacity which can be marketed on the vari-ous points of the network is intertwined. Capacity is determined by analysing scenarios that are likely to create network bottlenecks. The firm capacity adopted is the maximum capacity that does not produce bottlenecks under standard conditions of network use. The same approach is used to deter-mine the infrastructure construction work neces-sary to increase capacity.

The determination of capacity depends on the network’s characteristics

The modelling process used to determine the ca-pacity of a network depends on several parame-ters, in particular the technical characteristics of the infrastructure, the network’s operating con-straints and the quality of the gas transmitted.

Technical characteristics of the infrastructure

The transmission network primarily consists of pipelines and compressor or interconnection stations. The technical characteristics of this in-frastructure are already known for existing and approved facilities, or are provisional for new in-frastructure projects.

• The technical characteristics of the pipelines that influence the network’s capacity are the diame-

ter, maximum safe pressure (MSP), length and roughness. Load losses in the pipeline (name-ly, the fall in pressure that occurs as the gas is transmitted through the structure) depend on these characteristics. As a result, the capacity of a transmission network is directly linked to the load losses generated in the pipes.

• The compressor stations raise the pressure of the natural gas in the pipes. The technical characteristics of the compressor stations are primarily their power, the maximum and minimum flows they can compress, and their compression rate limits (the ratio between downstream and up-stream pressure).

• The characteristics of other network infrastruc-ture, such as the regulation valves that generate specific load losses, also affect capacity.

Operating constraints

The operating constraints result from the minimum pressure levels that are required at different points on the network to allow the gas to be transmitted and delivered. They are determined to allow GRTgaz to meet the following obliga-tions:

• its public service obligations with regards to sup-plying the distribution networks;

• its contractual obligations under the connection agreements signed with each of its industrial clients.

The heating value of natural gas

The physical capacity of a transmission system is expressed in volume flow rate (m3), whereas trading between shippers and/or consumers is conducted in terms of energy (Wh). In order to market capacity that is consistent with the needs of its customers, GRTgaz makes assumptions about the calorific value of the gas entering the network based on the flows observed at each entry point.

ANNEXE 2 determination of the network’s commercial capacity

_ 75

APPENDIX

An offer designed to reflect network utilisation assumptions

GRTgaz also bases its offer on network utilisa-tion assumptions in order to market capacity that meets the needs of the market. The capacities are interdependent and sometimes competing. GRT-gaz favours the most useful capacities.

Breakdown of flows

The gas flows on the network depend on the uti-lisation of capacity subscribed at entry and exit points, the level of consumption and the use of storage sites.

Certain entry points are used in preference to oth-ers depending on the market situation and the arbi-trage decisions made between the different sources of supply. GRTgaz takes many supply scenarios into account with different weather conditions to eva- luate gas flows and configure its offer accordingly.

Such assumptions or flow scenarios are made using data on past flows and expected trends. They cover a wide array of weather conditions, from cold peaks (18) to the minimum consumption levels typically observed in August, as well as the utilisation of underground storage facilities according to temperatures and demand for natural gas.

Operating conditions

The determination of capacity is carried out for normal operating conditions and based on gas flow breakdown assumptions that are considered to be realistic and acceptable and on the full avail-ability of the facilities.

The validity framework for the firm capacity GRT-gaz offers allows each shipper to fulfil its public service obligations (19), notably through under-ground storage withdrawals in winter and injec-tions in summer.

Special situations

The examination of different potential supply strate-gies, some of which are outside of the assumptions that are considered to be realistic and acceptable, leads GRTgaz to identify limiting conditions of opera-tion (‘CLER’). When a limiting condition of operation is reached, the network is congested and minimum flows are required at the entry points and beyond the congested point. The principal conditions con-cern land entry points in the north of France (con-gestion in the north and west-east directions) and the transmission of natural gas to the south-east of France (congestion in the south-east direction).

These special conditions are shared with the mar-ket, notably through the ‘Winter Outlook’, which has been published by GRTgaz at the time of each gas winter period since 2012.

For example, west-east congestion is shown below.

Above a level of consumption corresponding to a cold temperature, the increase in gas flows from the network’s other entry points (with the excep-tion of Fos), combined with maximum use of the North-South link, causes a network bottleneck in the west-east direction. In such a case, Obergail-bach must be topped up to supply the eastern part of the network.

TIGF

Dunkirk

Taisnières

Obergailbach

Oltingue


Montoir-de-Bretagne

Pirineos

Network interconnection pointLNG terminalsStorage siteCompression stationSaturated infrastructure

EXAMPLE: THE ‘OBERGAILBACH MINIMUM’

18. A period of extremely low temperatures over three consecutive days, as occurs statistically once every fifty years: decree No. 2004-251 of 19 March 2004 on public service obligations in the gas sector.

19. Decrees No. 2004-251 and No. 2006-1034 of 21 August 2006 on access to underground natural gas storage sites.

76 _

APPENDIX

GRTgaz is committed to building relationships of trust with all local stakeholders to ensure the suc-cessful integration of the transmission network throughout France by favouring the emergence of solutions that are shared and adapted to each case.

Determining the route with the least impact

Gas pipeline projects are subject to detailed stu-dies in order to identify the best possible solutions.

The impact study is conducted by a third-party ex-pert in consultation with local authorities, associa-tions and interested parties to identify all potential consequences for the environment and to define the best way to avoid, limit and make up for these consequences.

An active consultation policy

Information is given to all of the interested parties very early on in the process at formal and informal meetings. Such dialogue has taken on a new di-mension with the public discussions organised by the National public debate commission for seve-ral recent projects. Thanks to these discussions, GRTgaz teAMS get to hear other opinions, which allow useful adjustments to be made to the pro-jects. At the end of these discussions and once the studies have been completed, the route chosen becomes the subject of a public inquiry, which al-lows further adjustments to be made to cater for local factors.

As much as possible, GRTgaz strives to meet the expectations expressed and to provide guaran-tees in terms of the ecological, agricultural and socio-economic impact on the areas crossed. A charter sets out the company’s territorial commit-ments as part of a proactive approach specific to each project.

Ensuring safety

Regulatory obligations regarding safety and the environment have a significant influence on in-vestments. GRTgaz applies a rigorous manage-ment process to ensure industrial safety and secu-rity on the transmission network.

Each project is the subject of a safety study that results in enhanced protection measures, if necessary: thicker pipes, protective slabs and specific monitoring equipment. The pipes are made out of steel and welds are inspected using radiography or ultrasound. An insulating cover and cathodic protection system protect pipes from corrosion.

On the worksites, a Safety Passport is given to all participating contractors. Safety Trophies are also awarded in partnership with the Construction and public works organisation for risk prevention (OP-PBTP) in recognition of high performance.

Identifying and enhancing our archaeological heritage

GRTgaz has entered into a partnership with the National institute for preventive archaeological research (Inrap) to meet two goals: to prepare ar-chaeological fieldwork far ahead of construction work in order to allow enough time for research without delaying major projects and to make the most of archaeological discoveries.

Protecting agriculture

A total of 90% of pipeline routes are located in rural areas. GRTgaz has signed a national agreement with the Federation of farming trade unions (FNSEA) and Chambers of agriculture, detailing its commitments and its subsidy and compensation scheme.

The aim is to minimise the impact of works on farmland, to preserve the quality of the soil and to guarantee the restoration of the land crossed:

APPENDIX 3 execution of major projects

_ 77

APPENDIX

pre-sorted soil layers are put back in place, ditches and slopes are re-graded, and fences and drain-age are restored.

Respecting the environment and favouring biodiversity

Promoting biodiversity is a major part of the sustainable development policy of GRTgaz, whose com-mitment is recognised by the ‘National strategy for biodiversity’ label. Ecologists are involved in the very early stages of routing to establish inventories and then throughout the work and restoration phases.

As a founding member of the ‘Linear infrastruc-ture and biodiversity club’, GRTgaz has entered into partnership agreements with the Federation of regional parks of France, the National museum of natural history and Natureparif to ensure best practices are implemented during the laying of pipes and the maintenance of easement perime-ters. The ecological management of sensitive and forest areas allows rare species to thrive.

GRTgaz is also dedicated to the promotion of our natural heritage. It has joined the Biodiversity fund (FDB) to support the completion of a biodiversity atlas. It contributes to the creation, planning and maintenance of paths under a partnership with the French ramblers federation.

Minimising the impact of the facilities

Above-ground facilities are integrated into their environment as best as possible. The technical options that emit the least amount of CO2 are favoured. GRTgaz replaces old compressors in its stations with high efficiency electro-compres-sors or turbo-compressors. Since 2005, this pro-gramme has led to a ten-fold reduction in nitro-gen dioxide (NOx) emissions and a 47% reduction in carbon dioxide (CO2) emissions.

Network operation schemes are optimised to continuously reduce the network’s motive power, currently restricted to 0.5% of transmitted energy.

GRTgaz also uses innovative processes to limit the venting of gas during maintenance and repair

work. ‘Gas booster’, which recovers and re-injects gas into the network via a mobile compressor, is a case in point.

Optimising the economic benefits

The impact of worksites on the regional econo-my and job market is significant for many sectors: materials, clearing, earth-moving, civil engineering, transport, construction, landscaping, hotels, restaurants and convenience stores, etc.

GRTgaz works with the Chambers of commerce and industry and state job centres to involve local businesses and people who are looking for work in its worksites.

pavillon vert ®: an illustration of the commitment of grtgazto its sensitive sitesPavillon Vert ® illustrates GRTgaz’s de-sire to abide by sustainable develop-ment principles when managing its sensitive worksites:

• safety on the site and in the imme-diate vicinity, actions to promote employment and local economic benefits, high-quality information and relationships with partners and residents;

• economical use of water and energy, anti-pollution measures, limitations on site machine traffic;

• compliance with the project schedule, optimised guarantees so as to limit the impact on gas consumers, cus-tomer satisfaction.

Flown on the building site, the Pavillon Vert ® flag is raised or lowered accord-ing to the results of internal and exter-nal audits performed by specialist firms at the beginning, middle and end of the work on the site.

78 _

GLOSSARY

GLOSSARY

Backhaul Capacity: capacity on the National network that allows the shipper to carry out nominations in the opposite direction to the main flow direction when gas can only flow in one direction.

Balancing Zone: a group of Entry Points, Deliv-ery Points and Title Transfer Points within which the shipper must ensure that gas is balanced. There are two Balancing Zones: the North Zone and the South Zone. The North Zone is split between Balancing Sections H and L.

Client: the ultimate consumer of natural gas.

Conditions of Delivery: GRTgaz obligations re-garding the physical characteristics of the natural gas that it delivers (pressure, temperature, etc.).

Connection contract: the contract between GRTgaz and a client that specifies the conditions under which connection infrastructure will be constructed, operated and maintained, and the Conditions of Delivery.

Connection Facilities: Connections and Delivery Points that link a user site or a Distribution Net-work to the Transmission Network.

Connection: a transmission structure that connects the Transmission Network and one or more Delivery Stations; it is solely or mainly used to supply a Client or a Distribution Network. A connection is a part of the network.

Consumer Delivery Point: The point at which gas is delivered to a consumer that is connected to the Transmission Network. Each Consumer Delivery Point is connected to a single Exit Zone.

Conversion Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to delivering in the form of L- or H-gas and to withdrawing simultaneously in the form of H- or L-gas.

Cumulative Imbalance: the sum of the ship-per’s residual Daily Imbalances after consideration of the purchase and sale of volumes that exceed the Daily Imbalance tolerance and the mid-range of cumulative imbalances.

Daily Capacity: the maximum quantity of ener-gy that GRTgaz commits itself to withdrawing, transmitting or delivering every day.

Daily Imbalance: the difference between the sum of the quantities injected and withdrawn by the shipper every day, for each Balancing Zone and for each type of gas in the North Zone.

Delivery Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to delivering to a Consum-er Delivery Point, a Transport Distribution Inter-face Point or a Network Interconnection Point.

Delivery Point: the point at which GRTgaz sup-plies a recipient with all or part of the gas spec-ified in the Transmission Contract. Each Delivery Point is connected to a single Balancing Zone.

Delivery Station: a facility located at the very end of the Transmission Network which meters, regulates and reduces the pressure of gas deliv-ered to a consumer or a Distribution Network.

Distribution Network: medium- or low-pres-sure pipelines that supply gas to consumers that are not directly connected to the National network or to a Regional Network.

Entry Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to withdrawing every day at a given Entry Point.

Entry Point: the point at which the shipper sup-plies GRTgaz with all or part of the gas specified in the Transmission Contract. Each Entry Point is connected to a single Balancing Zone.

_ 79

GLOSSARY

Exit Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to delivering every day to all Delivery Points connected to one given Exit Zone, at one given Network Interconnec-tion Point, or at one given Transport Storage Interface Point.

Exit Zone: a group of Consumer Delivery Points, Regional Network interconnection points and Transport Distribution Interface Points for which an Exit Capacity has been defined on the Na-tional network. Each Exit Zone is connected to a single Balancing Zone.

Firm Capacity: capacity whose utilisation the operator is able to guarantee at any time throughout the subscription period under normal operating conditions.

H-gas: natural gas with a high calorific value.

Hourly Delivery Capacity: the maximum quan-tity of energy, expressed in MWh (GCV) per hour, that the operator commits itself to supplying every hour to a Consumer Delivery Point.

Interruptible Capacity: capacity whose utilisa-tion the operator is not able to guarantee at any time throughout the subscription period.

L-gas: natural gas with a low calorific value.

Link Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to transmitting every day to a link between two Balancing Zones.

Link: an oriented pair of Balancing Zones on which a Link Capacity is defined.

LNG Terminal: a facility that receives, stores and regasifies Liquefied Natural Gas (LNG) and injects it into the main regasified LNG network.

National network: high-pressure, large-diam-eter transmission infrastructure that connects the interconnection points to the neighbouring Transmission Networks, storage sites and LNG terminals; the Regional Networks, certain indus-trial consumers and the Distribution Networks are connected to the National network.

Network Interconnection Point (PIR): a physical or notional interface point between the Transmission Networks of two operators.

Regional network interconnection point (PIRR): a physical or notional point on the GRT-gaz Regional Network that interconnects with the adjacent operator’s Transmission Network.

Regional Network: high-pressure transmission infrastructure that supplies gas from the National network to consumers or Distribution Networks that are not directly connected to the National network.

Regional Transmission Capacity: the maximum quantity of energy, expressed in MWh (GCV) per day, that GRTgaz commits itself to transmitting on the Regional Network as far as a Consumer Delivery Point, a Transport Distribution Interface Point, or a Network Interconnection Point.

Releasable Capacity: firm capacity that the shipper commits itself to releasing at any time to GRTgaz upon the latter’s request.

Shipper: a party that enters into a Transmission Contract with GRTgaz. The shipper is, depend-ing on the circumstances, the eligible client, the supplier or their instructing party, as defined in article 2 of the Law of 3 January 2003.

Storage Site: a facility that is used to store natural gas in the summer, when consumption is low, and release it in the winter, when consumption is high.

80 _

GLOSSARY

Title Transfer Point (PEG): a virtual point con-nected to a Balancing Zone where a shipper can transfer gas to another shipper.

Transmission Contract: the contract between GRTgaz and a shipper that lays down the con-ditions under which GRTgaz commits itself to withdrawing quantities of gas provided by the shipper at one or more Entry Points or Title Trans-fer Points and to delivering quantities of gas with the same energy content at one or more Delivery Points or Title Transfer Points.

Transmission Network: high-pressure trans-mission infrastructure that supplies gas to directly-connected industrial consumers and to Distribution Networks; the Transmission Network consists of the National network and Regional Networks.

Transport Distribution Interface Point (PITD): a physical or notional interface point between a Transmission Network and a Distribution Net-work.

Transport Storage Interface Point (PITS): a physical or notional interface point between a Transmission Network and a storage group.

1 Kwh 1 GJ 1 therm 1 MBTU

1 m3 of natural

gas

1 barrel oil equivalent

(boe)

1 ton oil equivalent

(toe)

1 Kwh 1 0.0036 0.0341 0.0034 0.0949 0.00059 0.000086

1 GJ 277.8 1 9.48 0.948 26.35 0.1634 0.0239

1 Therm 29.3 0.10551 1 0.1 2.78 0.0172 0.0025

1 MBTU 293.1 1.06 10 1 27.81 0.1724 0.0252

1 m3 of natural gas 10.54 0.038 0.36 0.036 1 0.0062 0.0009

1 barrel oil equivalent (boe) 1,700 6.12 58.01 5.8 161.29 1 0.15

1 ton oil equivalent (toe) 11,630 41.87 397 39.7 1,103 6.8 1

CONVERSION OF GAS uNITS

uSEFuL LINkS

www.grtgaz.com

www.gasinfocus.com

www.cre.fr

www.entsog.eu

www.acer.europa.eu

www.gie.eu.com

www.aie.org

www.ec.europa.eu

www.eurogas.org

www.developpement-durable.gouv.fr

www.statistiques.developpement-durable.gouv.fr


TIGF

Dunkirk

Taisnières

Obergailbach

Oltingue

Jura


Montoir-de-Bretagne

570

620100

223

100

270

520

410 27080

230

370180

37

H 640B 230

Direction of �ow of natural gasFirm capacity in GWh/d (to be con�rmed as part of the implementation of the single market place for France)

Project in implementation phaseProject in study phaseProject under consideration

LNG terminals

Network interconnection points

Balancing zone

National network

Regional network

Compression stations under construction

Underground storage facilities

Compression stations

165225

mAp OF THE GRTgaz NETwORk IN 2024

HEAD OFFICEImmeuble Bora

6, rue Raoul Nordling92270 Bois-Colombes Cedex

0033 (0)1 55 66 40 00

GRTgaz - SEINE VALLEY26, rue de Calais

75436 Paris Cedex 090033 (0)1 40 23 36 36

GRTgaz - ATLANTIC COAST AND CENTRE10, quai Émile Cormerais

BP 7025244818 St-Herblain

0033 (0)2 40 38 85 00

GRTgaz - RHONE VALLEY AND THE MEDITERRANEAN33, rue Pétrequin

BP 640769413 Lyon Cedex 060033 (0)4 78 65 59 90

GRTgaz - NORTH-EAST24, quai Sainte Catherine

54000 Nancy0033 (0)3 83 85 35 52

GRTgaz - ENGINEERINGImmeuble Delage

7, rue du 19 mars 196292322 Gennevilliers Cedex

0033 (0)1 56 04 01 00

GRTgaz is a limited liability company with capital of €538 165 490

Its head office is located at 6, rue Raoul-Nordling 92270 Bois-Colombes, and its business registration number is 440 117 620 RCS Nanterre

Media Library reference number: 2RTB0216

ISSN No. pending

Design and production: créapix

Illustrations: Lucie Bertrand - Photos credits: GRTgaz / Philippe Dureuil, Hubert Mouillade

Ce document a été réalisé par un imprimeur éco-responsable sur du papier FSC

November 2015

GRTgaz operates the high-pressure natural gas

transmission network that covers most of France. With

more than 32,000 km of pipeline and 26 compressor

stations, the GRTgaz network is the longest in Europe

and one of the most interconnected. In 2013, GRTgaz

invested €777 million to ensure the transmission

of natural gas under the best possible conditions of safety

and fluidity, as well as to enhance security of supply in

France and in Europe, while providing access to diverse

sources of supply. GRTgaz has around 3,000 employees.

Our goal at GRTgaz is to place our network, our offer

and our expertise at the service of energy solutions with

a future in France, in Europe and around the world.

HEAD OFFICEImmeuble BORA

6, rue Raoul Nordling 92270 Bois-Colombes Cedex

Tel.: 0033 (0)1 55 66 40 00

www.grtgaz.com

Construisons le transport de demain

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