Study on the benefits of additional gas interconnections between Iberian peninsula and the rest of Europe : final report.
Date: 2016-05-30
Institutions: Directorate-General for Energy
Subjects: France, Portugal, Spain, cost-benefit analysis, energy grid, energy policy, energy supply, gas, market, price of energy

Study on the benefits of additional 
gas interconnections between the 
Iberian Peninsula 
and the rest of Europe (REQUEST 
FOR SERVICES  
№ DG ENERGY/B1/2015-282) 

Final Report 

Client: DG ENERGY - Directorate В: Internal Energy Market 

Rotterdam, 15 April 2016 

                                                                                                                                    
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Study on the benefits of additional 
gas interconnections between the 
Iberian Peninsula and the rest of 
Europe 

Final Report 

Client: DG ENERGY - Directorate В: Internal Energy Market 

Rotterdam, 15 April 2016 

Per Jørgensen - Ramboll 

More information on the European Union is available on the Internet (http://www.europa.eu). 

Luxembourg: Publications Office of the European Union, 2016 

ISBN: 978-92-79-58250-9 

Catalogue number: MJ-02-16-421-EN-N 

doi: 10.2833/95106 

© European Union, 2016 

Reproduction is authorised provided the source is acknowledged. 

 
 
 
                      
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
About Ecorys 

At  Ecorys  we  aim  to  deliver  real  benefit  to  society  through  the  work  we  do.  We  offer  research, 

consultancy  and  project  management,  specialising  in  economic,  social  and  spatial  development. 

Focusing on complex market, policy and management issues we provide our clients in the public, 

private  and  not-for-profit  sectors  worldwide  with  a  unique  perspective  and  high-value  solutions. 

Ecorys’  remarkable  history  spans  more  than  80  years.  Our  expertise  covers  economy  and 

competitiveness;  regions,  cities  and  real  estate;  energy  and  water;  transport  and  mobility;  social 

policy, education, health and governance. We value our independence, integrity and partnerships. 

Our  staff comprises  dedicated  experts  from academia  and consultancy,  who  share  best practices 

both within our company and with our partners internationally. 

Ecorys Netherlands has an active CSR policy and is ISO14001 certified (the international standard 

for environmental management systems). Our sustainability goals translate into our company policy 

and practical measures for people, planet and profit, such as using a 100% green electricity tariff, 

purchasing carbon offsets for all our flights, incentivising staff to use public transport and printing on 

FSC or PEFC certified paper. Our actions have reduced our carbon footprint by an estimated 80% 

since 2007. 

ECORYS Nederland BV 

Watermanweg 44 

3067 GG Rotterdam 

P.O. Box 4175 

3006 AD Rotterdam 

The Netherlands 

T +31 (0)10 453 88 00 

F +31 (0)10 453 07 68 

E netherlands@ecorys.com 

Registration no. 24316726 

W www.ecorys.nl 

 
 
 
 
 
 
 
 
 
 
 
About Ramboll 

Ramboll is a leading engineering, design and consultancy company founded in Denmark in 1945.  

Today, we employ close to 13,000 experts and have a significant presence in the Nordic Countries, 

North  America,  UK,  Continental  Europe,  Middle  East  and  India,  supplemented  by  a  significant 

representation in Asia, Australia, South America and Sub-Saharan Africa. 

With  almost  300  offices  in  35  countries,  we  emphasise  local  experience  combined  with  a  global 

knowledge base. Ramboll operates within the markets of: Buildings, Transport, Planning & Urban 

Design, Water, Environment & Health, Energy, Oil & Gas, and Management Consulting. 

The  services  provided  in  connection  with  this  study  are  supplied  through  the  wholly  owned 

subsidiary,  Ramboll  Oil  &  Gas,  which  is  a  well-established,  independent  and  highly  regarded 

worldwide provider of offshore and onshore engineering consultancy in the oil and gas industry. 

Ramboll Oil & Gas is presently operating through offices in Denmark, Norway, UK, India, Qatar Abu 

Dhabi (U.A.E.), and USA – close to our major clients and partners.  

Throughout our work, we are able to ensure our clients the best and most economical solutions as 

we work independently of third party interests; an issue that allows us to act as a genuine advisor.  

Ramboll  offers  a  full  range  of  services  in  terms  of  transmission  and  distribution  of  oil  and  natural 

gas, from on-/offshore pipelines, compressor stations, metering systems to Supervisory Control and 

Data Acquisition (SCADA) systems; all involving technical studies, frontend engineering to detailed 

design and operation, alongside economic, institutional and environmental studies. 

All business units within the Ramboll Group share core values and knowledge across disciplines, 

working as one company in delivering total solutions to all of our clients.  

Ramboll 

Hannemanns Allé 53 

DK-2300 Copenhagen S 

Denmark 

T +45 5161 1000  

F +45 5161 1001 

E info@ramboll.com 

DK reg. no. 35128417 

www.ramboll.com 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table of contents 

1 

Introduction 

2  Findings and conclusions 
Main conclusions 

2.1

2.2

2.3

Findings and reflections 

Need for further maturing of projects 

3  Market Analyses of current and future situation 

3.1

Objectives, background and historical use of interconnectors 
  Objectives of increasing gas interconnection between Iberian Peninsula and rest 

3.1.1

1 

2 
2 
3 
5 

7 
7 

of Europe 

7 
  MidCat project is the main proposal for further increase in interconnector capacity 8 
9 
14 

Iberian Peninsula was late to be connected to the rest of Europe 

Iberian LNG import overcapacity 

3.1.2

3.1.3

3.1.4

15 
17 

3.2

Market and/or security of supply for Iberian Peninsula and for France and rest of 

Europe   

of Europe 

3.2.1

  EU and national objectives for gas market and interconnectors 
Historical use of existing gas interconnectors between Iberian Peninsula and the rest 

Libyan and Egyptian gas supply to EU via pipeline and LNG 

EU Supply/demand situation 
  EU Supply/demand impact on need for increased interconnection 
  Gas demand in EU 
Gas supply to EU – specific analyses of supply countries 
  EU and Norwegian gas production and supply 
  EU Gas supply routes from outside EU 
  Algerian supply to EU via pipeline and LNG 
  Norwegian gas supply to EU via pipelines and LNG 
  Russian gas supply to EU via pipeline and LNG 

20 
21 
21 
21 
24 
24 
27 
28 
32 
33 
34 
34 
35 
38 
38 
39 
40 
41 
42 
Spain, Portugal and France demand and supply 
  Demand forecasts have been uncertain – create wrong signals and decisions  42 
43 
  Gas demand forecasts Spain, Portugal and France 
44 
  Supply – sources and concentration 
47 
Gas prices and contracts 

EU security of gas supply – major cases and events 
  Disruption cases 

LNG supply from other sources without pipeline connections to EU 

France – increase in demand due to nuclear incident 

LNG supply disruption and reduction of supply 

Tunisia as transit for gas from Algeria to Italy 

TAP/TANAP pipelines and Shah Deniz gas 

3.4.1

3.4.2

3.5.1

3.5.2

3.5.3

3.5.4

3.5.5

3.5.6

3.5.7

3.5.8

3.6.1

3.6.2

3.6.3

3.6.4

3.7.1

3.7.2

3.7.3

3.3

3.4

3.5

3.6

3.7

3.8

4  Transportation tariffs 

4.1

French regulated transportation tariff overview and comments 
  Overview 

4.1.1

50 
50 
50 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.1.2

Impact of establishing one zone in France from 2018 

4.1.3

  Assessment of French transmission system 
Spanish regulated transmission tariffs overview and comments 

Tariff barrier for use of interconnection between Spain and France 

Auctioning of capacity, CAM, Capacity Allocation Mechanism 

UBI (Use-it-and-Buy-It) capacity offer 

Use of gas storage in South of France for Spanish gas 

Enagas examples on impact of LNG terminal and transportation tariffs 

Conclusions on tariffs 

4.2

4.3

4.4

4.5

4.6

4.7

4.8

51 
52 
53 
54 
55 
55 
55 
55 
56 

5 

Interconnectors – identifications and technical solutions 

5.3.1

5.3.2

5.4.1

5.4.2

5.4.3

5.8.1

5.8.2

5.8.3

5.8.4

Cost and comparison 

Internal strengthening of Spanish and French system 
  Definition of full MidCat and alternative solutions in France 
Firm or interruptible capacity – probability calculations 

57 
57 
Technical solutions for additional interconnectors 
Existing interconnectors between Spain and France and agreed network additions  57 
59 
France-Spain interconnector - Eastern corridor - definitions 
59 
  MidCat definitions 
62 
  MidCat – first phase – Girona-Carcassonne 
67 
Full MidCat 
67 
67 
72 
73 
73 
Line pack and reduced energy consumption 
Connection between France and Germany, Reverse flow and odorisation problem  73 
Portugal - Spain  – 3rd interconnector 
75 
  Description of 3rd interconnector 
75 
76 
  Portugal capacity of interconnectors, LNG and storage 
  Portugal drivers behind the 3rd interconnector 
77 
  Cost benefit consideration for Portugal-Spain 3rd interconnector 
78 
MidCat cost summary including Eridan, Arc Lyonnais, 3rd interconnector to Portugal  79 
79 
Fos LNG extension – Capmax project 
81 
81 
82 
83 

KRK LNG terminal in Croatia and terminals in Greece 

Baltic Sea LNG terminals 

Technical Conclusions 

5.1

5.2

5.3

5.4

5.5

5.6

5.7

5.8

5.9

5.10

5.11

5.12

5.14

5.13

  GALSI pipeline 

6  Cost benefit analyses 

6.1

6.2

6.3

Benefits of increased interconnection between Iberian Peninsula and rest of EU 

North-South or South-North supply assessment and methodology 
  Normal market situation – ENTSO-G green and grey scenarios for demand – 

6.2.1

revised supply from North-West European production 

6.2.2

6.2.3

  Security of supply 
  Quantification of supply cases – methodology 
Supply cases and balances for France, Spain and Portugal combined – yearly 

balances 2025 – Green and Grey scenarios 

6.3.1

6.3.2

6.3.3

  Normal supply situation – Grey and Green scenarios – different prices 
  Security of supply – disruption of gas supply from Russia or Norway 
  Disruption of LNG supply from Qatar, Algerian supply or transit via Tunisia 

84 
84 
85 

85 
85 
86 

87 
87 
90 
92 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.3.4

6.3.5

France – increased demand for power sector in case of nuclear reduction 

  Conclusions on the yearly flow cases 
Comparison of interconnector cost with new and expanded LNG terminals 

93 
94 
95 
96 
Price differences between Iberian Peninsula and rest of EU 
  Price differences historical 
96 
  Benefits of interconnector to limit price differences in green and grey scenario  97 
99 
  Conclusion on benefit of price differences 
99 
  Qatar gas to UK, Belgium creates higher prices in Spain, Portugal 
100 
  Russian pipeline gas to Iberian Peninsula 
101 
101 

Security of gas supply to rest of EU 
  SoS cases, probabilities and quantification of cost savings from Iberian 

LNG price increase in Security of Supply situations 

6.5.1

6.5.2

6.5.3

6.5.4

6.5.5

6.5.6

6.6.1

6.4

6.5

6.6

interconnection 

6.7

6.8

6.9

6.10

6.11

6.12

Shorter shipping distance 

Algerian short range LNG supplied by pipeline 

Storage uses in South France 

Increased gas production in Algeria and Trans Saharan Gas Pipeline 

Comparison of cost and benefit 

Conclusions 

7  References 

101 
102 
102 
103 
103 
104 
104 

106 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
1 

Introduction 

The consortium of DNV GL, Ecorys, ECN and Ramboll was awarded the Study on the benefits of 

additional gas interconnections between the Iberian Peninsula and the rest of Europe. Ramboll is 

carrying out the study with Ecorys as Quality Assurance.  

After the award of the contract, a kick-off meeting was held in Brussels on 18 May 2015 with 

participation of representatives from the EU Commission, the Contractor Ramboll and Ecorys, and 

some of the stakeholders from Spain, France and Portugal.  

An inception report was prepared with further detailing of the methodology, sources to be consulted 

and identification of stakeholders. The inception report was circulated to selected stakeholders for 

commenting, and these have as far as possible been taken into account in the present interim 

report.  

A draft interim report was submitted in September and a final interim report in October after 

receiving comments from the client and stakeholders. The outcome of the interim report was 

presented in a meeting with stakeholders and the client in Brussels on 16 October 2015. 

A draft final report was submitted in January 2016 and presented in meetings with stakeholders and 

the client in Brussels on 27 January and 6 April. As part of this process, comprehensive comments 

were received of which some have been incorporated. Other comments would require additional 

work which was not possible to perform within the framework of the contract.  

Three of the main stakeholders, Enagas, TIGF and GRTGaz have developed a technical study on 

the possible use of the MidCat in different phases. The study was made available to Ramboll mid-

July and has been used as input to technical assessment herein. The study and results are 

summarised and commented in Chapter 3 of the present report. It has been outside the scope of 

the present report to replicate these calculations as they are based on TSO in-house knowledge.  

Bilateral meetings have been held with the following stakeholders:  

•  Enagas – kick-off meeting and telephone meetings  
•  GRTGaz – telephone meetings and physical meeting in Paris on 20 July 2015 
• 
TIGF – telephone meetings and physical meeting in Pau 23 on July 2015 
•  CRE – telephone meetings 
•  ELENGY – telephone meeting 
•  Engie – telephone meeting and video meeting on 28 August 2015 
•  REN – telephone meetings 

In connection with the meetings some internal documents with analyses and viewpoints have been 

exchanged between the parties. 

The focus of the study has been on the MidCat project between France and Spain, and 
consequently less work has been done on the 3rd interconnector between Portugal and Spain.  

The overall budget for the study was 75,000 EUR with a maximum of 75 man-days. 

1 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2  Findings and conclusions 

2.1

  Main conclusions  

• 

• 

• 

This report cannot be the sole basis for decision making about additional gas interconnectors 

due to uncertainties. However, we find that sufficient evidence for establishing additional 

interconnectors has been found to initiate detailed feasibility and conceptual analyses to create 

a firm basis for decision making and final investment decision. 

The uncertainty about the actual gas demand in EU (and not only the countries involved) 

results in high uncertainty of the results and how the actual flow would be. As an example this 

study does not directly include the impact of Nord Steam 2. 

The quantitative cost-benefit analyses for additional interconnectors become very uncertain. 

However, the analyses clearly raise some questions which may be easier to communicate:  
•  Shall it be possible to supply all parts of EU with gas transported by pipeline from inside 

Europe? 

•  Shall EU be able to withstand long term disruption of gas from one of its main external 

suppliers – Russia, Norway, Algeria or Qatar? 

• 

Increased interconnector, as the MidCat, is justified as it will integrate the Iberian gas market 

with the rest of EU in low demand scenarios, where there is little need for LNG import to EU, 

and at the same time make LNG terminals on Iberian Peninsula available for security of supply 

situations (Russia or Norway disruption) in particular in high demand scenarios where LNG 

terminals in the rest of EU will not have sufficient capacity. Thus there will be a case for the 

interconnector in more demand cases, with prevailing flow direction depending on EU demand 

and LNG versus gas hub prices. 

•  Security of supply can to a certain degree be created by only establishing the first step of 

MidCat, while full market integration will require large capacity and removing internal bottle 

necks in France in particular for North to South flow. This will include the Arc Lyonnais and 

Eridan projects. However, only a part of the capacity and hereby the cost for these pipelines 

can be allocated/attributed to the Iberian interconnector. 

• 

If new LNG receiving terminals are established in North and Eastern Europe for security of 

supply reasons, they will contribute to increased North-South flow in the Interconnector as 

Norway and in particular Russia will seek new markets further away in EU. With a saturated 

interconnector, the Iberian Peninsula will be isolated.  

•  With limited LNG import to EU, the dominating LNG exporters can choose to use Northern 

European LNG terminals and hereby in a similar way create congestion on the interconnector 

and isolate the Iberian markets.  

•  Portugal is, as the most remote part of EU, depending on gas from Algeria and LNG. The 3rd 
interconnector between Spain and Portugal can be seen as an integrated part of the MidCat 

project, as the main purpose will be increasing security of supply by getting access to the 

integrated EU market. Without MidCat there will be limited benefit from the project.  

The MidCat pipeline should preferably be established with the same capacity as the Eridan 

project, which may increase the ultimate capacity from 8 to 20 bcm/year.  

The high border tariffs between France and Spain, which are expected to increase further 

when France establishes one market zone from 2018,  contributes to splitting the Iberian 

• 

• 

Peninsula from the rest of the EU gas market, in particular for short term trade.  

•  A stepwise implementation of the interconnector is possible when accepting that mostly 

interruptible capacity will be available after the first stage MidCat. 

2 

 
 
 
 
2.2

  Findings and reflections 

•  Existing interconnector capacity between the Iberian Peninsula and the rest of EU is small 

compared to other main periphery interconnectors. This is found to be due to historical and 

technical/geographical reasons, as direct gas pipelines crossing the Mediterranean Sea to 

Spain were hindered by water depth until the technology was improved. Initially the Iberian 

Peninsula was operated as on Island based on LNG supply.  

•  Historically, the flow in existing interconnectors has been entirely from North to South. This 

reflects very particular global supply situation during the last 5 year with diverging global gas 

prices and historical long term contracts for Norwegian supply to Spain. Further, as the main 

LNG supplier to Europe, Qatar has chosen to use their own terminals in UK rather than the 

Spanish LNG terminals.  

•  Short Interconnector between Spain and France (MidCat first phase- 224 km) can contribute 

with some firm capacity (120 GWh/day from South and 80 GWh/day from North) under certain 

conditions, based on a shared study by the TSOs. However, there may also be conditions 

where there will be bottlenecks in the French systems. Further, such first phase can contribute 

with interruptible capacity with high probability and hereby increased security of supply even if 

systems in France and Spain are not strengthened. Implementation of new capacity allocation 

mechanism with focus on short term booking may unlock such capacity. In Spain probability 

estimates have been done, while more work needs to be done to determine in which situations 

capacity will be available in France.  

• 

French one market zone policy may conflict with a wish for additional interconnector capacity to 

Iberian Peninsula with firm capacity, available at all time. This is because firm capacity will 

require substantial investments in the French system to maintain one market zone. One 

solution to accept the one zone policy could be that the firm capacity is limited to avoid such 

excessive investments. 

• 

France, Spain and Portugal all have overcapacity of LNG receiving terminal as compared to 

present depressed consumption. There is a potential for sharp increase in demand when/if 

economy picks up again in South Europe. Yearly balances show that France has sufficient own 

capacity of LNG import facilities unless in a situation with high demand and low LNG prices 

compared to pipeline gas prices.  

• 

Iberian-Europe interconnector shall be seen in context with Italian supply route from Algeria 

and Libya and new routes from Turkey, like TAP which is likely to push Algerian gas towards 

Spain. There has already been a move of Algerian gas towards Spain instead of Italy.  

•  Algeria has potential for increased gas production from conventional and unconventional 

sources, savings on own consumption and for transit for other gas sources, like Trans Saharan 

Gas Pipeline. Hereby, there will also be potential for increased export to EU. Increased Iberian-

Europe pipeline capacity with reasonable cost may accelerate gas production in Algeria.  

•  North-West European gas production is likely to decline in coming years – The Netherlands, 
UK, Germany and Denmark all expect a decline in production, while Norway expects a stable 

or small increase. Norway uses its present system with high load factor, which makes it difficult 

to re-route gas from France to Germany. Should Norway decide to increase capacity to 

Germany or Denmark, it would be possible to increase EU import of LNG or Algerian gas via 

Spain.   

3 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
•  Nord Stream 2 is a game changer in North-West Europe and hence the overall North-South 

balance in Europe. However, it is still uncertain if new gas will be supplied or it will be re-

routing of gas from other transit routes like Ukraine or Belarus. As Russia loses market share 

in Ukraine and as LNG terminals are established in Lithuania and Poland, there is a need for 

Russian gas to find new markets further away as in UK or Iberian Peninsula. 

•  Russia and Qatar are the two main contenders for EU gas market at present as it is found that 

other pipeline players use their full capacity and that only Qatar and Algeria are significant 

players on the LNG market. It still has to be seen if new LNG suppliers want to enter into the 

battle for the EU market.  

Disruption of Russian gas to Central Europe, like Germany, Czech and Slovak Republics, can 

to a certain degree be replaced by use of the Spanish and French LNG terminals. This can be 

done as a combination of re-directing Norwegian gas via Germany and Algerian gas via Italy 

as well as use of the new pipeline Artere des Flandres to redirect some Norwegian gas and 

LNG via Belgium. However, it can also be expected that LNG terminals elsewhere in EU will be 

used.   

•  Disruption of Norwegian supply will have some of the same impact as disruption of Russian 
supply. Although, the lost volumes would be smaller there may be more direct impact on the 

French/Iberian supply situation with a need to move even more gas from Spain to France. This 

is because Algerian gas will still be supplied by pipelines via Spain. However, also in this 

situation there may be preference for using other LNG terminals in EU.  

•  Difference in odorisation policy in South and North Europe makes it impossible to have reverse 
flow at present. The cost of changing the system will probably be very high – in the order of 

500 MEUR. The focus is therefore on giving space for LNG in the Iberian and French market 

by re-directing pipeline gas before entering into the area.  

•  Disruption of Algerian supply can be replaced by increased LNG import to Portugal and Spain. 

This event will therefore not increase the physical need for increased import from France. 

However, it is likely that such event would increase LNG prices and hence increase use of the 

pipeline.  

• 

LNG supply disruption cannot be ruled out and will in particular impact Spain, France and UK 

in Europe. This would create need for import of gas to Spain from Norway and Russia via 

France. There is sufficient capacity in France for this in low demand scenario. The probability 

of such scenario may be higher than recognised so far. During the last year, three LNG 

exporting countries; Egypt, Yemen and Libya have halted their supply. Qatar is at present by 

far the largest LNG supplier to Europe.  

• 

• 

Tunisia should be addressed in same way as Belarus in security of gas supply analyses to 

Europe as a transit country from a main supplier to the internal European gas market. In case 

of disruption of supply, it will be possible to redirect gas via Spain to Europe. The probability of 

a disruption is low, but recent terror attacks can give reason for concern.  

French high dependency of nuclear power may result in repetition of “Fukushima” in Europe, 

although with low probability with  increase in gas consumption. Based on the existing CCGT, 

the increase can be in the order of 15 bcm/y. In high demand scenario there will be a need for 

France to import LNG from Spain in such case, while French LNG terminals will be sufficient in 

other scenarios.  

4 

 
 
 
 
 
 
 
 
 
 
• 

The technical solution for the MidCat project is based on work carried out before the open 

season 2010. The routing and cost estimates have not been updated. From the ongoing work 

the definition and cost estimates on French and Spanish side are very different. For the first 

phase of the MidCat project the following findings are made:  
• 

Length 224 km, assumed DN 900 (36”) and firm capacity of 120 GWh/day from South and 

• 

• 

80 GWh/day from North under certain flow conditions in particular in France.  

Total cost estimate of less than 500 MEUR, but uncertain as it seems as if Spanish side is 

underestimated and French side is overestimated. 

It is cheap to prepare for future increase in capacity and the increase to DN1200 would 

only increase cost with a third, while capacity would be more than doubled. 

•  Offshore solution should be considered if it becomes too expensive to go for the onshore 

route in France. However, this is less mature than onshore solutions and may change time 

schedule.  

•  We suggest considering re-naming the project as original MidCat definition is outdated and 

biased with respect to use and purpose. Find name for first section from Hostalrich (near 

Girona) in Spain to Barbaira (near Carcassonne) in France.  

• 

For the full MidCat there is a need for additional capacity in France and Spain. This includes a 

DN1200 Eridan project with a length of 220 km. The overall firm capacity will be 230 GWh/day. 

The investment of the full MidCat, as defined in the shared report, is more than 2000 MEUR. 

More options are possible for a full development and only the Eastern solution has been 

evaluated. There is uncertainty about which part of the investment should be allocated to the 

increased interconnection and which part to the one zone policy in France. Alternatively, only 

sections of the Eridan and Arc Lyonnais pipeline could be established.  

• 

• 

The cost of the 3rd interconnector between Spain and Portugal will be in the order of 360 
MEUR for all phases in Portugal and initial  phases in Spain  

The cost of the full MidCat and 3rd interconnector to Portugal will in total be about 3000 MEUR; 
however, some part of the cost should be attributed to better integration internally in France 

and at the entry to France. With a shared cost for such items the cost for full MidCat including 

the interconnector to Portugal will be 1650 MEUR.  

•  As the cost of capacity is much lower for the first step MidCat and because of  uncertain 

market conditions, a preliminary conclusion is to only establish the first phase and to limit the 

firm capacity to a level which does not change the one zone philosophy in France. There will 

still be extra interruptible capacity for security of supply situations. 

2.3

  Need for further maturing of projects  

• 

The technical definition of the MidCat needs to be matured with respect to routing, design, 

environmental and social impact to define a clear cost estimate for final decisions. This should 

also include an offshore solution as a reference for cost estimation.  

•  Capacity calculations should be based on probabilistic analyses for France as it has already 
been done for Spain. Hereby, the possible spare capacity for interruptible transportation in a 

first phase MidCat can be quantified. Such calculations should take into account the change in 

market conditions when one zone is established in France in 2018.  

5 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
•  Capacity calculations for the full MidCat including Arc Lyonnais and Eridan should also include 
the impact of Nord Stream 2, the reverse flow from Switzerland and the 3rd interconnector 
between Spain and Portugal. 

• 

Transportation tariffs are presently influencing the use of the pipeline system and LNG import. 

As part of development of new network code, the possibilities to remove this barrier should be 

found.  

•  Renewable energy like wind, solar, hydro and biomass will impact the use of gas and create 

large variations from year to year. South-West Europe is further impacted by large variations in 

use of gas as result of weather conditions. There will be possibilities for using such variations 

to free capacity in the transmission system. It is recommended to further analyse these 

aspects. The variations are expected to increase when countries like France increases the use 

of renewable energy as new legislations impose reduction of fossil fuel.  

6 

 
 
 
 
 
3  Market Analyses of current and future 

situation  

3.1

  Objectives, background and historical use of interconnectors 

3.1.1

  Objectives of increasing gas interconnection between Iberian Peninsula and rest of Europe 

The objectives of increasing gas interconnection capacity between the Iberian Peninsula, consisting 

of Spain and Portugal, and the rest of Europe are to support regional trade opportunities and 

arbitrage, and to enhance security of gas supply in the EU. These objectives were detailed in the 

EU Madrid Declaration on March 2015, in which it was stated that France, Spain and Portugal: 

“recognize that a fully and integrated gas market, eliminating bottlenecks, connecting the regional 

markets, maximizing the diversification of the gas portfolio through new sources and routes, will 

reinforce the negotiating capacity and increase the European security of supply. In this sense, the 

President of France, the Prime Ministers of Spain and Portugal, also agree on the need to actively 

asses in order to complete the Eastern gas axis between Portugal, Spain and France, allowing 

bidirectional flows between the Iberian Peninsula and France through a new interconnection project 

currently known as the MIDCAT. The 3rd Portugal-Spain interconnection should be developed in 
accordance.”1 

Fulfilling these objectives lead to assessing the possibility of increasing gas imports from Algeria to 

Europe through the Iberian Peninsula. This would unlock the potential of the country’s large gas 

reserves that are more than the double the reserves of Norway, which presently is EU’s largest gas 

supplier. Furthermore, Algeria may have considerable reserves of shale gas available for export 

and besides, other African countries may likewise export natural gas via Algeria. One example of 

this is the Trans Saharan Gas Pipeline from Nigeria via Niger to Algeria and further to Europe.  

In recent years, comprehensive investments have been made in LNG receiving facilities in south 

western Europe, with a combined import capacity on the Iberian Peninsula of 77 bcm/year or more 

than the double of the present consumption. However, these LNG plants have been operating 

below their full capacity. The three countries mentioned above – and in the same context – are 

likewise committed to “contribute to a strategy with robust LNG infrastructures in their countries” 

and to “diversify their gas supply with a comprehensive LNG strategy that addresses also 

geopolitical concerns.” 

Therefore, the possibility of using the LNG facilities and also underground gas storages will 

significantly enhance creation of a fully and integrated gas market as intended.  

Supplying gas from between the Iberian Peninsula and the rest of EU is today restricted by lack of 

physical pipeline capacity, long-term contracts for use of existing capacity and preference to 

existing users of the transportation system. The new EU wide Network Code on Capacity Allocation 

Mechanism went into force in 2015 and should contribute to more focus on flexible short-term 

contracts for capacity. Further, a challenge as the different practise in use of odorisation of natural 

gas in the transmission system has to be solved or bypassed. This is in particular an issue between 

South Europe who odorizes gas in the transmission system and Germany who only does this in the 

distribution system.  

1 SOURCE: Madrid Declaration 4 March 2015 

7 

 
 
 
 
 
 
 
 
 
 
 
 
                                                           
Gas demand in EU was severely struck by the financial crises and high oil and gas prices during 

the last five years. The use of renewable energy – in particular photovoltaics (PV) which quadrupled 

from 2010 to 2015 – impacted the use of gas for power generation. Moreover, the Fukushima 

accident in Japan resulted in large quantities of LNG being diverted away from the European 

market, due to increased demand in Japan to make up the loss in nuclear generating capacity. This 

event now seems to have passed, and a situation where new LNG supplies from Australia and the 

USA are entering the market has developed. An increased possibility of physical exchange of 

natural gas between the Iberian Peninsula and the rest of Europe may contribute to optimising 

Europe’s benefit of such supply situation. 

Russian gas supply and transit via Ukraine and Belarus have been impacted by the conflict in 

Ukraine. So have the plans for new infrastructure such as the offshore pipeline South Stream 

across the Black Sea, which was cancelled and replaced by plans for the TurkStream pipeline to 

Turkey. Also, plans for constructing the Nord Stream II pipelines to Germany were launched. Thus 

there is still significant uncertainty about the decisions on new gas supply routes from Russia. 

Iberian Peninsula is the only part of EU (apart from Malta and Cyprus), which cannot be fully 

supplied by pipeline gas delivery.  

Increasing cross-border interconnections for exchange of natural gas across the Pyrenees will be 

an important step towards increasing the robustness of the EU Internal Energy Market. As such, it 

“constitutes a fundamental dimension to build the European Energy Union, i.e. to ensure secure, 

affordable and sustainable energy, which is a key instrument to strengthen the competitiveness of 

the European industry and therefore the growth and jobs across the EU,” [ref. the Madrid 

Declaration]. 

3.1.2

  MidCat project is the main proposal for further increase in interconnector capacity 

The MidCat project, with an eastern connection between Spain and France is the main proposal for 

increased interconnector capacity between Iberian Peninsula and the rest of Europe. The project 

was initially launched almost a decade ago, and an open season was held in 2010 to test the 

market response.  

Since the open season for MidCat in 2010, at least three major events have impacted the gas 

market and the cost benefit of additional interconnections. These are:  

•  Arabic Spring – resulting in less gas supply from North Africa to the EU and high oil prices from 

2011 to 2014 

Fukushima nuclear accident in Japan – resulting in high LNG prices from 2011 to early 2015 

• 
•  Ukraine conflict – resulting in re-routing of gas within the EU, including export to Ukraine, 

cancellation of the South Stream project and Russian focus on gas export by pipeline to China.  

These events have created increased uncertainty about LNG supply and demand globally and 

about Russian gas supply to Europe. Therefore the market response from 2010 may not be valid 

anymore.  

In addition to these major events, the period was characterised by a depressed gas market as 

shale gas in USA pushed coal to the EU replacing the use of gas in power generation. The second 

wave of the financial crisis hit the South European countries particularly hard, but was generally a 

major contributing factor to the decline in gas consumption in the EU.  

8 

 
 
 
 
 
 
 
 
 
 
 
  
On the issue of gas supply, some of the major events have been the commissioning of the Nord 

Stream gas pipelines, which pushed large volumes of gas of the same magnitude as the idle LNG 

terminals on Iberian Peninsula into North Europe, the decision to cancel the Nabucco pipeline, 

opting for the Trans Adriatic Pipeline (TAP) via Italy, and finally the decision to cancel the South 

Stream pipeline across the Black Sea. A new LNG terminal came into operation in Lithuania, thus 

breaking the Russian monopoly in that region.   

Major non-events of the period were the fact that shale gas did not develop in Europe and that the 

giant Russian Shtokman gas field was postponed or cancelled. 

3.1.3

Iberian Peninsula was late to be connected to the rest of Europe 

The connection between the Iberian Peninsula and the rest of EU is small seen in a European 

context. The capacity is only 5 cm/y via two smaller pipelines crossing the Pyrenees in the western 

part. In late 2015, the capacity of the two pipelines was increased to 7 bcm/year from South to 

North as firm capacity. Illustrated in Figure 3-1 below.  

The Iberian Peninsula is hereby the only part of the EU, apart from Malta and Cyprus, which cannot 

be fully supplied by natural gas by pipelines.  

Figure 3-1 Gas transmission line in countries around the western Mediterranean Sea 

9 

 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
This can be compared to the large connections between Italy and the rest of EU with several large 

diameter pipelines crossing the Alps from Austria (TAG pipeline) and Switzerland (TENP pipeline) 

and connections to Slovenia and Croatia. The combined capacity of the Italian grid from the rest of 

EU is approximately 55 bcm/y, while the reverse capacity from Italy to Austria and Slovenia is 

approximately 7 bcm/year. It has recently been decided to increase the capacity from Italy to 

Switzerland and further to Germany and France via the TENP pipeline.   

Both Spain and Italy are connected to Algeria via Morocco and Tunisia respectively. Spain has also 

a direct pipeline, Medgaz, from Algeria with a capacity of 9 bcm/year. The Medgaz pipeline is 

prepared for a second pipeline.  

Spain, Portugal and Italy all have LNG import terminals, and in particular Spain has developed 

many terminals to compensate for the lack of pipeline connections and lack of indigenous gas 

production and suitable geological locations for large scale underground gas storage. The purpose 

of the Iberian LNG facilities is hence a combination of import and storage. An overview of the 

terminals is presented below in Figure 3-2.  

The difference between the connections between the Iberian Peninsula and the rest of EU and 

between Italy and the rest of EU can to a certain degree be explained by different history and 

decisions made in the past, before implementation of the internal gas market in year 2000.  

Spain 

Development of the natural gas system in Spain was initiated in the 1960´ies based on small 

volumes of own production and by import of LNG to Barcelona. Only small volumes of gas were 

found in Spain and the initial development of gas in Spain was based on LNG imported from Libya 

including LPG which was extracted at the plant in Barcelona. The use of gas in Spain was initially 

based on LPG as the main source.  

10 

 
 
 
 
 
 
 
 
 
 
 
Figure 3-2 LNG import terminals - storage and regasification – and pipeline im-/exports of natural gas 

(red) to the area under consideration with present gas interconnectors (blue) 

Spain became member of the EU in 1986 and shortly after an agreement was made to import gas 

from Norway via France. The first connection from Algeria via Morocco was developed in the early 

1990’ies with a dual pipeline crossing of the Strait of Gibraltar. The reason for selecting transit of 

natural gas through Morocco was that the offshore pipeline technology at that time did not allow for 

pipe laying in deep waters as would be encountered if a direct route from Algeria to Spain was 

settled for. Only when the technology was developed after year 2000, a direct pipeline, Medgaz, 

was constructed and commissioned in 2008.  

France was initially involved in the Algeria - Morocco pipeline to Spain. However, France withdrew 

and instead the Spanish gas system was developed as a meshed grid with the purpose to supply 

natural gas to the country as such and to connect to the country’s LNG terminals. The Spanish 

transmission network consists of smaller diameter gas pipelines that are less suited for transit of 

large volumes of natural gas. Italy has for comparison implemented a strategy based on large 

diameter north-south transmission pipelines making it easier to transit gas to Europe through the 

country.  

11 

 
 
 
 
 
 
 
 
 
 
 
 
Portugal 

Portugal had the choice between LNG import or pipeline via Spain and Morocco from Algeria. It 

was decided to go for the pipeline connection, which helped to make the Maghreb-Europe gas 

pipeline project viable. Later, Portugal has constructed an LNG import terminal and an underground 

gas storage for security of supply and market reasons. Presently, there are two pipelines connected 

with Spain.  

France 

The French natural gas supply was initially based on indigenous production from the Lacq gas field 

north of the Pyrenees. The gas system was developed to transport gas from the South of France 

towards Paris. Later on gas was supplied from the Netherlands via Belgium, from Russia via 

Germany and from the middle of the 1990’ies from a direct pipeline from Norway.  

LNG was developed early in France with the first LNG to Le Havre in 1965 and from the early 

1970’ies to Fos near Marseilles, mainly based on import from Algeria. Later on more LNG terminals 

were constructed.  

When the indigenous gas fields in the south were depleted, some were converted into underground 

gas storages. In addition, dedicated gas storages in the area were developed. The overall storage 

capacity in France is more than 12 bcm and the maximum combined withdrawal rate is 213 

mcm/day, while the injection rate is 108 mcm/day. This shall be compared with the peak load of 

approximately 330 mcm/day, showing that the capacity of the storage is much more important than 

the pipeline supply during a security of supply crises, allowing for a flexible use of import pipelines 

on short term.   

In recent years, the possibility of producing shale gas has been a topic for much public debate in 

France. So far it has been decided to exclude the use of hydraulic fracking and projects are put on 

hold. However, plans are under consideration to develop bio-methane to natural gas quality, 

according to among others GRTGaz.  

France is today connected to the following EU member states: Belgium and Germany to the North 

and Spain in the South. Further, France is indirectly connected to Italy via Switzerland; the offshore 

pipeline Franpipe connects Norway and France directly with a capacity of 52 mcm/day. The French 

system is not directly connected to neighbouring countries Italy, Luxembourg or UK. Also, there is 

not yet any direct offshore pipeline connections from Algeria, although a spur line to Corsica is 

planned as part of the Galsi pipeline, connecting Algeria and Italy as a combined off- and onshore 

pipeline that will cross Sardinia. Due to the delay in the Galsi project, it is now been considered to 

establish a FSRU on Corsica.  

12 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interconnections within the EU 

The interconnections between the centre of EU and the periphery differ with respect to number of 

connections and capacity. This is due to difference in geography, history and gas supply sources. 

There are still a few “missing links” for which interconnections are being considered. 

Area 

Connection 

Popula-

Gas 

Pipelines  Capacity 

Capacity to 

tion  

consum

from rest of 

rest of EU 

(million) 

ption 

EU (bcm/y) 

(bcm/y) 

Iberian Peninsula 

France 

UK and Ireland 

The 

50 

60 

Netherlands 

and Belgium  

(bcm/y) 

30 

78 

Italy 

Austria, 

55 

64 

Switzerland 

Denmark/Sweden 

Germany 

Ireland 

Sweden 

Greece 

UK 

Denmark 

Bulgaria 

15 

5 

10 

10 

Baltic  

Poland  

10 

Cyprus 

Malta 

Greece 

Italy  

1 

1 

4 

4 

1 

3 

7 

0 

0 

2 

2 

3 

3 

3 

1 

1 

0 

0 

0 

5 

45 

55 

5 

15 

2 

3 

7 

20 

6 

To be 

increased from 

2018 

5 

0 

1 

Will be 

increased with 

TAP project 

Missing links  GIPL being 

implemented 

Missing links 

Missing links 

Table 3-1 European cross border pipelines and their capacities 

The comparison shows that the Iberian Peninsula is relatively poorly connected to the rest of EU as 

compared to other areas with respect to capacity. Interconnectors have traditionally been used in 

flexible ways as periphery areas often have different suppliers. As an example the UK-Belgium 

interconnector was originally constructed for export from UK. Now the line is used for export during 

summer and import during winter as EU storage facilities are used. Further, the existence of the 

interconnector between UK and the Continent contributed to attract new supply routes from 

Norway.  

In conclusion, Interconnectors serve to ensure supply from the periphery to the centre of EU and at 

the same time ensures access to the internal market for gas and contributes to ensure security of 

supply for the entire EU.  

13 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.1.4

Iberian LNG import overcapacity 

Spain has a large LNG import capacity, which is significantly underutilised. In 2015, the LNG import 

to Spain was only 15 bcm, while the capacity is 69 bcm, resulting in an overall utilisation of only 22 

per cent. It can be seen as a paradox that LNG is shipped to the UK and other north-western 

European countries and indirectly supplied by pipeline to the South targeting Spain via France as 

there is a net flow from the UK to Belgium and further to France during the summer period. The 

additional time spent in sea transport from typical Middle-East exporters of LNG is approximately 

one week. 

Figure 3-3 Transport route for Qatari LNG to UK – bypassing Iberian Peninsula 

The reason for bypassing Spain on its way to Europe cannot be found from price differences alone.  

It is more likely to be caused by take-or-pay obligations, the overall EU supply/demand balance, 

long term contracts, difference in market liquidity, shared ownership of receiving terminals, 

destination clauses etc. Long-term contracts under favourable conditions, giving incentives for 

Spanish gas import from the North. Qatar is the main LNG supplier to Europe and has heavily 

invested in the UK import terminal South Hook. The South Hook Terminal, located at Milford Haven 

14 

 
 
 
 
 
 
  
 
in Wales is part of the Qatargas 2 integrated value chain. Thus, the use of UK terminals instead of 

Spanish and French terminals is due to such long-term commitments, but also because the cost of 

using South Hook terminal can be seen as sunk cost from a Qatar view point.  

The LNG terminals in the UK, and North-West Europe in general, have the advantage of the 

existence of a liquid market place where it is possible to sell gas with good visibility. Qatar, which is 

by far the largest LNG supplier to EU, is co-owner of gas receiving terminal in UK and is one of the  

reasons for not balancing the LNG market by using Spanish LNG terminals.  

Spain has a total LNG import capacity of 69 bcm/y, which was developed in response to strong gas 

demand forecasts during the boom years before the financial crises and to regional priorities.  

The  actual decisions about supply of gas are not only based on short term prices. Information 

about long term contracts is not public available and it is therefore difficult to assess the impact. 

However, LNG receiving terminals are often seen as part of integrated supply chain including 

upstream facilities, liquefaction, sea transportation and regasification. In such cases there are no 

incentives to choose the regasification terminals in Spain, Portugal and France.  

3.2

  Market and/or security of supply for Iberian Peninsula and for France and 

rest of Europe 

Benefits of the existing and possible new gas interconnections between the Iberian Peninsula and 

further implementation of the internal EU gas market  

increased use of LNG terminals in the Iberian Peninsula  

the rest Europe are in the present study found to include the following:  
• 
• 
• 
• 
• 
better negotiation power and position for European shippers, implying lower gas prices. 
•  more ‘sustainable’ transport of natural gas through pipelines than transport of LNG over short 

diversification and new gas supply, including additional supply from Algeria  

better and  more even use of gas storage facilities in France and Spain 

distances 

• 

increased security of gas supply to EU and to the involved countries and regions. 

Implementation of the internal EU gas market  

The implementation of the internal gas market includes creation of transparent market places and 

hereby also price visibility. At present there is not a well-functioning gas market in Spain and 

Portugal and no liquid market place exists. Similarly, a major gas supplier like Sonatrach from 

Algeria is not directly selling gas to end users in France, The benefit of implementation of the gas 

market may be lower prices for consumers in average.  

Increased utilisation of LNG terminals 

Increased use of LNG terminals in Spain and Portugal can replace construction of new terminals 

elsewhere in Europe and can create competition between LNG terminals. This will depend on the 

overall cost of bringing gas to consumers and taking into account long term commitments and 

national obligations, such as the N-1 principle for security of supply.  

Diversification and new gas supply 
Seen from an overall EU perspective, an increased gas transport capacity between the Iberian 

Peninsula and other EU member states can be part of a new major supply route from Algeria to the 

integrated EU gas market. Hereby it could also act as a back-up for supply via Tunisia to Italy. 

15 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-4 Gas transmission pipelines exiting Algeria with exports to EU (Financial Times 23 June 2015) 

A considerably much higher capacity of an integrated Spanish-French gas transmission system 

could be seen as an alternative to the proposed Algerian-Sardinia-Italy (Galsi) pipeline, which is 

planned for a yearly capacity of 8 bcm/year. This could likewise promote construction of new major 

gas infrastructure in northern Africa as e.g. the Trans-Saharan Gas Pipeline. By establishing more 

capacity between Algeria and Spain and between the Iberian Peninsula and France, it will be 

possible to ensure a high security of gas supply in the entire South-Western part of EU. The issue 

is at which cost this can be done and to quantify the benefit of this additional security of supply.  

Strengthening of the interconnections between the Iberian Peninsula and the rest of EU may open 
for new supply routes from the South to EU:  

• 

Increased gas import and import flexibility from Algeria – leading to possible installation of 

the second Medgaz pipeline, with an increased capacity of 8 bcm/year.   

•  Promote new supply routes like Trans-Saharan Gas Pipeline from Nigeria via Niger and 

Algeria  

The connection may also contribute to improved use of existing infrastructure: 
•  Use of underutilised LNG receiving terminals in Spain and Portugal  
• 
Increased use of large gas storage facilities in South of France  

A new gas interconnector between Spain and France could be constructed in stages as it would to 

some degree work to alleviate bottlenecks in the two gas transmission networks. The ‘missing link’ 

itself is no more than approximately 200 km and by having this interconnector in place transhipment 

of large quantities of piped natural gas across the border could commence. Naturally, the actual 

use will depend on the use of underground gas storage, LNG terminals and CCGTs.  

16 

 
 
 
 
 
 
 
 
 
 
Better negotiation power and position for European shippers, implying lower gas prices. 

An additional larger connection will imply better bargaining position for shippers on both sides of the 

French Spanish border. South of the border shippers would have the possibility of sourcing gas 

from the rest of Europe as an alternative to Sonatrach, NNPC, and other LNG suppliers. North of 

the border in France an upwards shippers and consumers would have the possibility to engage with 

a larger variety of LNG suppliers, while companies such as Sonatrach, NNPC, and Gas Naturel, 

could begin competing with other larger wholesale suppliers further up in Europe.   

Sustainable transport of natural gas through pipelines than transport of LNG over short 

distances 

Pipeline gas transport over shorter distances is in general more environmentally sustainable than 

LNG as liquefaction and regasification is more energy intensive than pipeline transportation. The 

overall use of gas for liquefaction and regasification may be up to 10 per cent of the gas supply. If 

the short range transportation of LNG from Algeria to France (and Spain) could be replaced by 

more pipeline transportation, this will have environmental benefits and save gas in Algeria. 

However, there may be other environmental impact of gas pipelines.    

Increased security of gas supply to EU and to the involved countries and regions. 

Security of gas supply in EU is mainly organised on national level according to EU regulation 994 

on security of gas supply. However, for larger events like disruption of Russian or Norwegian supply 

or disruption of LNG supply such national approach is insufficient. A main benefit for the EU of 

increased capacity of pipeline from Iberian Peninsula will be the possibility of increased use of the 

pipelines from Algeria and the use of idle LNG facilities. These aspects are seen as main drivers for 

the increased capacity.  

3.2.1

  EU and national objectives for gas market and interconnectors 

General – conflicting goals 

Transportation of natural gas is a physical activity. Gas can be transported in pipelines or as 

liquefied natural gas, LNG. The real economic cost of transportation is a.o. depending on the 

transportation distance, geography, cost of infrastructure, economics of scale etc. However, with 

creation of single zones, , the cost of transportation does no longer reflect the real cost, which 

depends on distance and dimensions with a high degree of economics of scale.  

On the other hand, it is also a goal to create competition which is the reason for unbundling of the 

transportation system from supply of gas and creating trading areas with uniform prices.  

Some of the contradictions between goals are:  

•  Creating of one national market place vs. creation of cross border trade  
•  Creating of one national market place vs. efficiency gains as this may require high 

investments 

•  Security of supply vs. competitive prices 

Increase of interconnections with firm capacity between the Iberian Peninsula and the rest of EU 

may make it more expensive to achieve a goal of having only one market zone in France from 2018 

by merging the present three zones, PEG Nord, PEG Sud and PEG TIGF.  

17 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
French gas market – unification of North-South as main priority  

France has experienced difference in prices between the different market zones. Since the opening 

of the gas market in 1998, the number of trading zones has been reduced and in 2012 there were 

only three zones; PEG North, PEG South and TIGF PEG.  

Figure 3-5 Development towards a unified natural gas market zone in France (Source: TIGF) 

In order to merge the different zones, it is necessary to invest in new gas infrastructure between the 

zones, assuming future supply situations. Some of these investments like the Val de Saone pipeline 

in ongoing. At present there is only limited transit through France to Spain and Switzerland 

respectively. Despite this situation, congestion has been experienced in the north of France in 2014 

when import of LNG was reduced and replaced by import of gas from Norway and Russia via 

Germany.  

Next step could be to create one zone including France, Spain and Portugal. This will require 

substantial extra investments, which may be close to an extra pipeline from North of France to 

South of Spain – a distance of 1500 km. The policy of one zone and thus one market price in 

France will move the price difference to the border to Spain.  

18 

 
 
 
 
 
 
The three TSOs in the South region; REN from Portugal, Enagas from Spain and TIGF from France 

have created two virtual interconnection points, combining the capacity of different physical 

pipelines. Also, common rules for capacity allocation have been implemented.  

Security of gas supply and solidarity  

The EU regulation of security of gas supply was implemented in response to the 2009 gas supply 

crises in Ukraine, when gas transit from Russia was halted for some weeks. The basic principles of 

the regulation are to ensure a robust system which on national level is sustainable even if the main 

supply is disrupted and to ensure solidarity between member states. Interconnections play a vital 

part in the fulfilment of the criteria for security of supply since they facilitate movement of gas in 

both directions.  

Energy Union - Preparation for future change in global market situation  

The Energy Union strategy has five mutually-reinforcing and closely interrelated dimensions 

designed to bring greater energy security, sustainability and competitiveness: 
•  Energy security, solidarity and trust; 
•  A fully integrated European energy market; 
•  Energy efficiency contributing to moderation of demand; 
•  Decarbonising the economy, and 
•  Research, Innovation and Competitiveness 

The Commission has highlighted 15 action points, of which no 2 concerns gas supply. 

“2. The EU needs to diversify its supply of gas and make it more resilient to supply disruptions. 

The Commission will propose a resilience and diversification package for gas in 2015- 

• 
2016 by revising the existing security of gas supply Regulation. 
• 

The Commission will prepare a comprehensive strategy for Liquid Natural Gas (LNG) 

and its storage, and 
• 

The Commission will work with Member States to develop access to alternative 

suppliers, including from the Southern Gas Corridor route, the Mediterranean and 

Algeria, in order to decrease existing dependencies on individual suppliers.” 

As part of this package meetings between EU Commission and Algeria and other North African 

countries have been held. 

19 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.3

  Historical use of existing gas interconnectors between Iberian Peninsula 

and the rest of Europe 

The existing French-Spanish interconnector pipelines have in recent years mainly been used for 

transport of gas from France to Spain. LNG prices have been higher than pipeline gas and as a 

result there have been no incentive to use the large – partly idle – LNG capacity in Spain for 

transport of gas to France. Also, Algeria, who has the possibility to export gas as LNG or as 

pipeline gas, has chosen to stick to oil indexed gas prices, which together with high oil prices have 

made their pipeline gas relatively more expensive than hub based pricing.  

Since the first months of 2015, there has been less flow in the pipelines. This coincides with 

increased flow in the pipelines from Algeria to Spain. The actual flow from France to Spain also 

depends on the overall physical balance in the entire EU. With increased production in Norway and 

increased import from Russia in third quarter of 2015, combined with LNG import to UK and 

Belgium, there was again a need for more flow from France to Spain.  

Figure 3-6 Daily gas exports via the interconnector at Port-de-Larrau and Biriatou 

In the open season procedure for the MidCat project, highest demand was for the Spain to France 

flow. Although what has been witnessed is almost entirely flow from north to south. The main 

reason for the flow from North to South is that the LNG prices have been relatively high compared 

to pipeline gas from the North, originating mainly from the Netherlands, Norway and Russia. With a 

weak demand for gas in the EU, the pipeline gas, and take-or-pay obligations, may have pushed 

gas further to the South. 

Long-term contracts for supply of gas to Spain from the North have also favoured the transportation 

from North to South. Algeria has traditionally used oil indexed gas contracts. With high oil prices 

this results in higher gas prices than the gas-to-gas competition in North-West Europe could justify, 

as gas prices has a higher elasticity than oil prices. In a situation with lower oil prices as at present, 

it is likely to have a more balanced situation with respect to gas prices.  

20 

 
 
 
 
 
 
 
 
 
3.4

  EU Supply/demand situation  

3.4.1

  EU Supply/demand impact on need for increased interconnection 

The overall EU supply and demand balance is impacting the need for increased interconnector 

between the Iberian Peninsula and the rest of EU. The increased interconnection capacity has been 

analysed in the ENTSO-G South Region, but the issue is impacted by factors outside the region.  

Contrary to electricity, which only can be transported economically over a few hundred kilometres, 

natural gas can be transported economically over thousands of kilometres by pipeline or even 

longer as LNG.  

It is therefore necessary to take an overall view on the benefits of additional interconnectors 

between Iberian Peninsula and the rest of Europe, as the present system is not only a bottleneck 

between Spain and France but also between North Africa – with huge gas reserves – and a Central 

European gas market, which may be negatively impacted by potentially declining gas supply from 

Russia, the Caspian Sea and Northern part of Norway. 

In this section the overall demand forecasts will be discussed based on the recent published 

ENTSO-G TYDP 2015 report. Gas supply will be discussed with a focus on indigenous supply 

sources, main supply sources by pipeline with a particular focus on Algeria and LNG supply, to 

supplement the ENTSO-G report, which focuses much on Russia and transit countries from Russia. 

Also, the cut-off time for ENTSO-G was in 2014 which allows us to take some more recent 

developments into consideration.   

3.4.2

  Gas demand in EU 

The ENTSO-G 2015 TYDP demand scenarios are used as the main cases in the present analyses. 

Since the preparation of these scenarios, the market situation for gas has changed somewhat due 

to lower oil prices and consequently lower gas prices for the oil indexed contracts. The gas demand 

in recent year for the entire EU and in particular for the Iberian Peninsula and France has been 

fluctuating due to impact of the financial crisis, gas prices and also meteorological conditions. In 

2014, which was one of the warmest years on record in Europe, the gas demand in France 

declined more than 16 per cent and in Spain almost 10 per cent. However, this year, where weather 

conditions have been more normal, the gas demand has picked up rapidly.  

The ENTSO-G TYNDP includes comparison of different scenarios for EU gas demand, including 

their own two main scenarios, the Green and the Grey. 

“The global context covers the price of gas and coal as well as the price of CO² emissions. 

The relative levels of these three prices influence the share of gas and coal in 

the power generation mix. The two considered global contexts are: 

21 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Green – the price scenarios correspond to 

Grey – the price scenarios correspond to the 

the “Gone Green” scenario from the UK 

Current Policies scenario from the 

Future Energy Scenarios ( FES ) document, 

IEA WEO 2013) document which is 

which is consistent with: 

consistent with: 

•  A high price of CO² emissions due to the 

• 

Lower price of CO² emissions as no new 

introduction of a carbon tax 

environmental political commitments 

are taken 

•  A continuous reduction in the oil-price 
linkage mitigating the increase of gas 

•  High energy prices following higher energy 

demand in absence of new 

price when oil prices increase 

Efficiency policies but with prices still too 

low to trigger the development of 

Renewables” 

Figure 3-7 Demand scenarios 

The two sceanrios are combined with respectively high economic and stagnat economic growth on 

one side and an electricity system based on renewable and on more traditional fuels.  

Figure 3-8 Comparison of gas demand outlooks (ENTSO-G – TYDP 2015) 

22 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
The graph shows the uncertainty about future natural gas demand in EU. This uncertainty for 

natural gas is higher than for energy in general as natural gas is the residual supply after wind, 

solar, biomass, coal and nuclear in the power and heat sector.  

The gas demand on the Iberian Peninsula is forecasted to grow faster than for most of the rest of 

Europe. 

Figure 3-9 Evolution of total annual gas demand on 2015 - 2035 period 

(Gas demand for electricity is based on data from ENTSO-E S0&AF 2014 - 2030) 

The figures shows the change in natural gas demand in different part of EU, with growth in Iberian 

Peninsula and East Europe, in particular Poland and decline in wind based energy systems of 

Germany and Scandinavia 

Some of the comments to the ENTSO-G scenarios, which we have not included in the quantitative 

analyses are:  
•  Oil and gas prices are high in both scenarios. This may be too optimistic. High oil and gas 

prices may imply lower demand than what would otherwise be the case.  

• 

The outcomes of the two scenarios – Green and Grey are very similar. This is because the 

environmental policy adopted in the Green scenario is counteracted by more rapid growth. It 

could be argued that the cost of green policy would slow down economy and that the Green 

scenario is optimistic with respect to use of gas as compared to the Grey scenario, as 

increased use of wind and solar could be accelerated and spread to more EU member states 
•  Assumptions about use of nuclear energy have previously shown to change rapidly as seen in 

Germany. Both visions used by ENTSO-G have the same assumptions, which in particular for 

France and Spain may be a very static picture. For example, the scenarios do not take into 

account that nuclear policy and implementation could change rapidly? 

23 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
•  Climatic change will by itself change gas demand, as seen in previous years. This is due to the 
need for heating and cooling, but also impact on hydro-, wind-, solar- and biopower. It is 

unknown how the gas sector should prepared to be back-up in case of unforeseen climatic 

conditions. In 2014 the gas demand was particularly weak due to the warm weather, while in 

the summer of 2015 the electricity sector in countries like Spain and Poland was dependent on 

the gas sector due to very warm weather and low reservoir levels. In such situation it is easier 

to move gas than electricity.  

•  An economic bounce-back from the financial and economic crises in 2008-2013 has not been 

foreseen in the scenarios. In particular in South Europe there may be room for rapid economic 

development due to spare capacity in manufacturing and other part of the economy. 

•  Demographic development inside EU and from outside. In general population is moving from 

the east to the west and north. Further, there is immigration from outside EU. Population 

growth is an independent growth factor in addition to the contribution to GDP. 

3.5

  Gas supply to EU – specific analyses of supply countries 

3.5.1

  EU and Norwegian gas production and supply 

EU gas production declined rapidly in 2014 with almost 10 per cent. The main producers are the 

UK, the Netherlands, Denmark, Germany and Romania. The main reason is the restrictions put on 

gas production in the Groningen field in the Netherlands emanating from earthquake recently 

registered around the fieldThe output from the field was in late November 2015 reduced from 33 to 

27 bcm/year. Such reduction will stretch the reserves over more years and hereby contribute to 

keeping up production over longer time. 

Germany and Denmark are exposed to a gradually inevitable decline in natural gas production, 

while the UK is depending on new fields coming into operation in expensive areas like West of 

Shetland. Further, many old gas fields offshore Denmark and UK are exposed to frequent 

unplanned maintenance due to ageing. At present it seems unlikely that shale gas will come into 

operation in EU in the near future. There may, however, be possibilities for drawing upon future 

new gas supply sources from Romania and Cyprus. These new sources of supply have been 

discounted in our present forecast, contrary to those by ENTSO-G, since the present reduction in 

prices has made them less likely. Also, Cyprus has entered into a preliminary gas export agreement 

with Egypt, and new supply will hence not impact the overall EU supply.  

24 

 
 
 
 
 
 
 
 
 
 
Our gas supply forecasts, based on national publications and own assessments, are shown below.  

Figure 3-10 Ramboll's gas supply forecasts, based on national publications and own assessments unit 

bNm3/year 

The production profile shows Ramboll combined EU and Norway production profile, showing that 

production will be on a plateau in the coming years before continuing the fall in production. We 

have kept the Norwegian supply constant as the natural decline will be replaced by new fields. The 

graph also shows that the majority of supply will be from the North of EU. 

ENTSO-G potential for EU gas production is shown below and includes a.o. Non-FID production 

from Romania and Cyprus with a combined volume of up to 20 bcm/year, which we have not 

included.(FID is final investment decision) 

25 

 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-11 Potential of EU conventional production 2015-2035 (ENTSO-G TYDP 2015) 

Whereas ENTSO-G expects a plateau in EU gas production around 140 bcm/y until 2025 and a 

further reduction to 60 bcm/y in 2035, we expect a reduction from the present 120 bcm/y to 

115 bcm/y in 2020, and 95 bcm/y in 2025 and 65 bcm/y in 2035.  

The Norwegian gas production has been almost constantly around 110 bcm in recent five years. 

Out of this the pipeline export has been around 100 bcm/y. Today’s level is approx.10 bcm lower 

than assumed only a few years ago, due to delays in project implementation. We expect, based on 

NPD data, and indications of project prospects, that the pipeline supply to EU will increase with up 

to 5 bcm/y until 2020 and hereafter stay on this level of 105 bcm/y until 2035. The total forecast is 

between 15 and 30 bcm lower than the ENTSO-G forecast for the first years, and somewhat higher 

for the period after 2025. There is a large uncertainty about field developments in Norway but there 

should be sufficient resources to keep up production.   

All in all we expect the supply from EU North-West Europe and Norway to be 230 bcm in 2020 

declining to 210 in 2025 and further to 175 bcm/y in 2035, with the majority of supply from Norway 

in the latter years as the Netherlands and UK will deplete their fields.  

In conclusion, we expect that the combined EU and Norwegian gas supply via pipeline will be 

approximately 20 – 30 bcm/y less than foreseen by ENTSO-G in the 2015 TYDP in the period from 

2020 to 2025.  

The development in gas supply from EU and Norway is a possible reason for launching of projects 

like Nord Stream II from Russia to Germany and for a project like Trans Saharan gas pipeline from 

Nigeria via Niger and Algeria to Spain. Also, the decline can support use of LNG terminals in EU.  

26 

 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-12 EU gas consumption and production from EU and Norway (BP Statistical review and ENTSO-

G and own assessment of production) 

In any case there is a substantial gap for external suppliers to cover. In the following, a brief review 

of the assumptions with respect to gas infrastructure and supply to the EU is presented. 

3.5.2

  EU Gas supply routes from outside EU 

The EU gas supply situation is described in the ENTSO-G TYDP with the following existing import 
routes. 

Table 3-2 Existing import routes of natural gas to Europe (ENTSO-G TYDP) 

27 

 
 
 
 
 
 
 
 
 
 
 
This description does not include the transit countries for Algerian gas supply. Here we will use the 

following more precise description: 

Source 

Algeria 

Route  

Spain 

Italy 

Sub-route 

Morocco 

Direct – Medgaz 

Tunisia 

Table 3-3 Export routes of natural gas from Algeria 

From a security of supply as well as from a market point of view, it is important to recognise that a 

major part of the Algerian gas is transported via transit countries. It is expected that a transit tariff is 

paid for use of transmission lines in the transit countries, which may impact shippers’ choice of 

transportation: by LNG or pipeline and also between the direct pipeline and via transit. 

With respect to security of supply, the gas supply situation in Algeria and Libya has been impacted 

by civil war and terrorists’ attack on gas infrastructure. This has not yet been experienced in the 

transit countries but cannot be ruled out.  

In addition to the existing pipeline routes, it is likely that the Trans Adriatic Pipeline, TAP, will be 

built. However, no decision has been made so far on the TurkStream, although recent development 

makes it more uncertain which could increase the likelihood of Nord Stream 2 The new 

development in Iran may open for new supply sources. New supply routes also includes Nord 

Stream II from Russia to Germany and PCI projects like GIPL, Baltic Pipe and Balticconnector, 

which may turn some Norwegian gas supply to Eastern Europe. 

The overall conclusion is that there is not a firm frozen picture of which boundary conditions will 

exist for the increased interconnection between the Iberian Peninsula and the rest of EU. This also 

tends to favour a stepwise development of a new Spanish-French interconnection. A stepwise 

development would ensure that the capacity matches the market situation.  

3.5.3

  Algerian supply to EU via pipeline and LNG 

Algerian gas supply has most impact on the gas supply to Spain, Portugal, Italy and partly France 

as a combination of pipeline supply and LNG.  

28 

 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-13 Algerian gas fields and supply routes to southern Europe (Sonatrach) 

Algeria is one of the most important gas producers and suppliers to the EU with a total production 

of 130 bcm/y according to Sonatrach annual report. However, a large part is used for re-injection, 

fuel use on fields etc. and only around 80 bcm/y is eventually marketed. The indigenous 

consumption outside the oil and gas sector is around 40 bcm/y leaving another 40 bcm/y for export 

to Tunisia, Morocco, Spain, Portugal and Italy by pipeline and as LNG.  

Algeria has potential for developing gas production substantially with a gas reserve base of 4500 

bcm conventional gas and potentially large volumes of shale gas. At present some volumes of gas 

are flared and a programme is being implemented to reduce this and recover the gas.  

Development of Algerian gas supply has been delayed due to security problems. Most visible was 

the terrorist attack on the BP/Statoil facilities in Amenas in 2013, which resulted in several fatalities. 

The consequence of the event has been increased focus on security and associated cost, which 

has delayed some field developments. It is likely that these fields will come into operation within a 

few years, again depending on the security situation.  

Algeria has potential for development of new resources as shale gas. The potential is big, but still it 

needs to be proven if the resources can be produced technically and economically viable. It is 

possible that shale gas production could start already within the next five years.  

The Trans Saharan Gas Pipeline is a potential new import route of Nigerian gas via Algeria. When 

the national gas system in Nigeria is being developed to Kano and the Algerian gas network 

stretches to the south, the missing link between the two systems will only be around 2600 km.  

29 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The Algerian gas export system includes three main pipeline routes. Transmediterranean I and II 

via Tunisia to Italy, Maghreb-Europe via Morocco to Spain and further to Portugal and Medgaz 

directly to Spain. Further, a fourth pipeline, Galsi, is planned for direct connection to Italy and via 

Sardinia with a spur line to Corsica. The present capacity and use of the pipelines are as follows:  

Pipeline / LNG 

Capacity (bcm/y) 

Use 2014 (bcm(y) 

Possible upgrade 

Transmediterranean  

Maghreb-Europe 

Medgaz 

Morocco and Tunisia  

LNG 

Total 

32.0 

11.6 

8.0 

4.0 

40 

95.6 

Table 3-4 Gas exports from Algeria 2014 

6.1 

7.1 

6.3 

4.0 

17.3 

40.8 

The daily use of the systems is shown in the graph below.  

32 

20 

16 

Figure 3-14 Gas flows from Algeria to Spain and Italy (Source: Enagas and Snam Rete Gas) 

30 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-15 Daily flows Algeria to Spain (Tarifa and Almerio) and France to Spain (Larreau) (Source: 

Enagas) 

The Trans-Mediterranean and Maghreb-Europe pipelines both go via transit countries. It is 

assessed that the transport tariff is more than 5 per cent of the transported volumes, paid either in 

gas or cash. In particular with high gas prices such transit tariff will favour the use of LNG export or 

direct pipeline.  

Technically it will be possible to increase the capacity of the Maghreb-Europe pipeline by adding 

additional compressor stations as the diameter of the pipeline is large enough for transporting up to 

20 bcm/y. The dual pipeline crossing of the Straits of Gibraltar also has sufficient capacity for such 

transport. The Medgaz pipeline is planned for an additional pipeline as landfalls have already been 

made for the second line.  

Algeria has two main LNG export facilities; Arzew and Skikda. The country was the first to use LNG 

from early 1960´ies as pipeline export was not possible at that time.  

The overall capacity of the two terminals is about 30 mt/y, including a rebuild Skikda terminal with a 

capacity of 4.5 mt/y which was brought into operation in 2013. This terminal is a replacement of the 

one which was destroyed by a fire back in 2004.  

Algeria has a very flexible system and can make decisions about export or use of gas. In recent 

years, while oil prices were high, high priority was given to indigenous consumption which 

increased rapidly. In 2014 the LNG export was around 17.3 bcm, including 2.6 bcm to Asia. The 

pipeline export was 23.5 bcm, of which 4 bcm to Morocco and Tunisia, while indigenous 

consumption increased by 12 per cent to 38 bcm.  

Due to the fall in oil prices in 2014, Algeria has moved from a solid surplus on trade and current 

account to a sharp deficit. In the short run this may be acceptable due to the large financial 

reserves. On the longer run, we consider that Algeria may give priority to increased gas export to 

support the economy. 

31 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.5.4

  Norwegian gas supply to EU via pipelines and LNG 

Norway became the main gas supplier to EU in 2014. The majority of gas supply takes place via 

the integrated gas pipeline system. 

Figure 3-16 Norwegian gas supply routes to EU (Source: NPD) 

The capacity of the system is more than 350 mcm/day, which was the maximum delivery in 2014.  

In 2014, the total delivery of gas was 101 bcm, corresponding to an average of 275 mcm/day. The 

present utilisation of the system is hence less than 80 per cent in average. However, when taking 

into account the need for repair and maintenance, the utilisation is approx. 85 per cent. With the 

planned increase in use, the utilisation will be close to 90 per cent. This means that there will be 

little flexibility to reduce supply to France and submit to Germany and further to the East.  

The capacity of the individual pipelines can not necessarily be added as it may be gas treatment 

plants and compressor stations which determine the overall capacity.  

32 

 
 
 
 
 
 
 
 
The Franpipe pipeline to Dunkerque has a capacity of 55 mcm/day, corresponding to more than 18 

bcm/y. The technical capacity of the five pipelines to the Continent is 246 mcm/day. In 2014 the 

total export by pipeline to the Continent was 75.2 bcm, corresponding to an utilisation of the system 

of more than 85 per cent in average.  

Gassco has analysed possibilities for additional capacity to the Continent to respectively the 

Netherlands and Denmark from where the gas could be sent to Poland via the PCI project Baltic 

Pipe, which is being analysed. So far these projects have not been decided. Also, it is presently 

analysed to build a new pipeline to the Barents Sea and connect to the existing system in order to 

prolong the plateau production for the entire sector.  

We therefore anticipate in the following analyses that Norway will have to deliver at least 10 bcm/y 

via Franpipe to France to maintain production. Of this, some volumes will be exported to Italy via 

Switzerland.  

Norway is exporting LNG from the Snöhvit terminal. The capacity is approximately 5.5 bcm/y. Gas 

is sold to many countries as the original market; USA, has replaced LNG import by shale gas. 

Norway has started to supply LNG to the new terminal in Lithuania. This is one of the first examples 

that Norwegian gas is replacing Russian gas close to the Russian border. Hereby, the previous 

sharing of the EU market has been broken, which may also open for new pipelines to the east.  

3.5.5

  Russian gas supply to EU via pipeline and LNG 

Russia is the second largest gas supplier to EU after Norway overtook as the leader in Q4 2014. 

The Russian gas supply impacts the possible need for additional capacity from Iberian Peninsula 

via the overall gas balance between pipeline and LNG supply and delivery to specific entry points.  

The Russian gas strategy changed in late 2014 after the Ukraine crisis when the South Stream 

pipeline was replaced by TurkStream and later by announcement of the Nord Stream II pipeline to 

Germany. It is still unclear if the TurkStream will go ahead and with which capacity especially 

following the increased tensions between Turkey and Russia.  

Further, Russia is developing the arctic Yamal LNG where Europe is the main goal as reloading 

from ice class vessels to the European system or reloading of LNG is expected to take place in 

Zeebrugge or other LNG facilities. Also, Russia is planning for new LNG export facilities in the 

Baltic Sea.  

On a global scale, the Russian – Chinese agreements on pipeline supply from Russia to China may 

change the overall LNG supply/demand balance by reducing the need for LNG in China and reduce 

the available gas for pipelines to EU.  

The Russian gas supply system is used for indigenous use and export. As the gas consumption in 

Russia is high during winter, it will be beneficial to export and store gas in Europe during summer. 

This is the reason why Russian companies have invested heavily in storage facilities. As Ukraine 

gas storage may no longer be available there will be some changes in supply situation.  

Traditionally, Ukraine has been the major transit route to EU. Further, the Yamal-Europe is 

supplying gas to Poland and Germany, and since 2012 the Nord Stream has been a major supply 

route with a capacity of up to 55 bcm/y directly to Germany.  

33 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
In the summer 2015, Russia launched the Nord Stream II project, consisting of two new pipelines in 

parallel to the existing two Nord Stream pipelines. The capacity would be the same, around 55 

bcm/y. It is still uncertain what should be the gas sources for these two pipelines. It could be that  

gas presently supplied via Ukraine, and/or Belarus/Poland via Yamal-Europe pipeline is re-routed, 

or that there be new sources like the shelved Schtokmann field.  As Russia is presently moving into 

recession, probably to be followed by lower growth than foreseen before the Ukraine crisis, there 

may also be some gas available as indigenous consumption will be lower than foreseen so far.  

The Nord Stream II pipelines are not included in the ENTSO-G-TYDP and can change the 

North/South balance in gas supply in EU and hereby also increase the supply of gas via Germany 

to France. Generally the more gas is being supplied by Russia in the east and central Europe the 

higher the likelihood for gas being flowed from north to south in the Iberian interconnector.  

3.5.6

  Libyan and Egyptian gas supply to EU via pipeline and LNG 

Libya was one of the first suppliers of gas to Spain, as LNG to Barcelona. In recent years, the main 

supply has been via pipeline – Green Stream – to Italy. The LNG supply stopped after the change 

in government and the ongoing civil war.  

Egypt was exporting up to 15 bcm LNG per year before the Arabic Spring, mainly to USA and EU, 

particularly Spain. One of the results of the Arabic Spring was to give priority to indigenous demand 

and Egypt has now turned to become an LNG importer.  

Egypt is now considering to import gas also via pipeline from Cyprus and Israel. The other obvious 

alternative would be to import gas from Libya, where there is large reserves. Due to the civil war 

and lack of stability in Libya this option has so far been postponed.  

The developments in Libya and Egypt show that North African countries may not be as stable as 

originally anticipated.  This can be seen as a treat for gas supply to the two Iberian countries, 

Portugal and Spain, which is highly depending on gas supply from Algeria. Also transit via Tunisia 

and Morocco may be exposed to risks. Plans to develop interconnections between the Arabic 

countries have so far not materialized. The interconnector will be able to ensure increased security 

of supply to the Iberian Peninsula. 

3.5.7

  TAP/TANAP pipelines and Shah Deniz gas 

The Shah Deniz II filed in Azerbaijan will be the initial source of gas to the Trans Adriatic Pipeline – 

TAP – which will transport gas from the Turkish/Greek border to Italy via Albania. The initial 

volumes will be 10 bcm from year 2020 with possibility to increase capacity to 20 bcm/y.  

Russia is planning the TurkStream from Russia to Turkey. This could also be a source for the TAP 

and other pipelines from South-East Europe to the rest of EU. However, there is considerable 

uncertainty about the progress of this pipeline and capacity as solutions with one up to four offshore 

pipelines are being considered.  

With the present development in Iran, it is likely that gas export to Turkey will be increased via the 

existing 56” pipeline between Iran and Turkey.  

If TAP will supply 20 bcm/y to Italy, it is likely that the import from Algeria will be reduced as the 

north-south capacity in Italy to a certain degree will be utilised by the TAP pipeline gas. This is 

illustrated by the figures below. 

34 

 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-17 Present and future main gas transmission lines to southern Europe 

3.5.8

  LNG supply from other sources without pipeline connections to EU 

LNG has the flexibility of technically free combination of supply sources and regasification via ship 

transport. In recent years a market for reloading has further developed as already known from the 

oil market, allowing for temporary parking of LNG, changing of ship size and even use of trucks for 

transportation of LNG to off-grid end users. The use of very large LNG vessels brings down the cost 

for long distance transportation. Contractually there is still a lot of constraints including long term 

contracts, destination clauses etc. 

The advantage of LNG transport is that the marginal cost of longer distance is small which allows 

for re-loading of LNG and regasification close to the end-users and hereby also to be flexible in 

case of rapid change in demand. This was most clearly shown in response to the Fukushima 

accident in Japan in 2011, which resulted in re-routing of LNG from the European market to Japan. 

The missing LNG to Europe was replaced by pipeline gas and coal as LNG prices increased, 

resulting in a low utilisation of LNG import facilities.  

The LNG market was until a few years ago divided into two main markets; the Atlantic and the 

Pacific. In the Atlantic market, LNG was shipped to North America and Europe, mainly from Middle 

East and Africa. Hereby, it was possible to re-route vessels to Europe from North America in case 

of a short term shortage. In line with the increase in US shale gas production there was no more a 

need for import of LNG to USA. Hereby the possibility for meeting a short term shortage in Europe 

also disappeared as shown in the cold spell of early 2013.  

As a replacement of the US import market, a South American import market has developed in 

recent years which due to the opposite seasonality than in Europe can replace the need for storage 

of gas. 

35 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Seen from a security of supply point of view, LNG has the advantage of many suppliers and the 

disadvantage that geopolitical events can influence the market on the supply as well as the demand 

side. Examples on this is the change of Egypt from being LNG exporter to become importer, the 

stop of LNG supply from Yemen and on the demand side the sudden increase in LNG import to 

Japan.  

For the interconnector between the Iberian Peninsula and the rest of Europe, the LNG market 

 Algeria preference  to sell LNG or pipeline gas 

influences the projects in several ways;  
• 
• 
•  Coincidence between gas supply by pipeline and/or LNG – can the same general infrastructure 

The cost of new re-gasification facilities compared to new interconnector 

be needed to transport gas to different sub-markets and storages – example is the Eridan 

pipeline project which will create more choices between LNG and pipeline gas 

•  Price of LNG on the world market and flexibility in contracts 
•  Preference for different suppliers and use of LNG for diversification of supply  

Answers to these questions do not necessarily follow a mathematical optimisation, and a number of 

paradoxes can be observed in the European gas market also impacting the use of the existing and 

possible new interconnector between the Iberian Peninsula and the rest of EU: 

LNG is supplied to North-West Europe and UK, while at the same time there is spare capacity in 

Spain and at the same time gas flows from France to Spain via pipelines Gas pipelines from Algeria 

to Spain are not fully utilised, but instead LNG is supplied to Spain and France. 

In 2014, the total LNG supply globally was around 333 bcm, divided on approximately a dozen 

export countries. Qatar was the largest supplier with more than 100 bcm, followed by Malaysia, 

Australia, Nigeria and Indonesia with between 20 and 35 bcm in the second tier. Trinidad & 

Tobago, Algeria, Russia, Oman, Yemen, Brunei, UAE, Peru, Norway and Equatorial Guinea were in 

the third tier between 5 and 20 bcm/y. Of these countries Oman and UAE has a combined LNG 

export similar to their pipeline import from Qatar. It could as such be claimed that the Qatar export 

is in reality 120 bcm/y. In 2015 and 2016 it is expected that substantial new capacity will be 

available from Australia. USA will slowly become an exporter by conversion of previous import 

terminal to export, while it is more unlikely that green field projects become viable. On the longer 

term, East Africa may become a new exporter as new major gas fields are found and planning of 

LNG export facilities is ongoing.  

.  

LNG supply to Europe was around 50 bcm and was hence less than 20 per cent of the world 

market. The supply to Europe mainly took place from Qatar and Algeria with a combined export of 

almost 40 bcm. In practise the possible diversification of supply to Europe is not taking place. This 

is partly because counties like Egypt, Yemen and Libya have halted LNG export temporarily or 

permanent.  

ENTSO-G TYDP does not consider LNG supply a possible security of supply concern. The recent 

development in Egypt, Libya and Yemen shows that it may be a too optimistic approach. Apart from 

supply problems like in Egypt and political unrest as in Yemen there may be technical and nature 

problems which may impact supply on shorter or longer term.  

The fact is that three of the LNG suppliers to EU; Egypt, Libya and Yemen, have halted LNG 

supply. This may be an overseen reason for the decline in LNG import to Europe.  

36 

 
 
 
 
 
 
 
 
 
In the security of gas supply analyses we will include a scenario with lack of LNG supply from Qatar 

for technical or other reasons.  

LNG vessels are becoming larger and more diversified. LNG from and to new arctic terminals 

requires special ice-class vessels. Smaller vessels are normally used for short range transport.  

The cost of transportation will depend on the availability of vessels and the day rates for vessels. It 

may take one week extra in transport to deliver a cargo to UK or Belgium instead of to Fos in 

France or Barcelona in Spain if a cargo arrives from Qatar. In case of supply crisis to Europe, which 

shall be covered by large volume LNG import, the availability of vessels may impact the prices for 

vessels and hereby also the choice of LNG re-gasification terminal.  

The recent widening of the Suez Channel will probably improve the LNG supply situation from 

Qatar. However, it also highlights the importance of this route. The route south of Africa is 

approximately 10,000 km longer than via Suez. This corresponds to an extra sailing time of almost 

4 weeks per load from Qatar, which shows that disruption of the Suez Channel may constitute a 

risk for LNG supply as well as for oil supply.  Whereas there are oil pipelines in parallel with the 

Suez Channel, such pipelines does not exist for LNG transportation.  

There are at present more than 20 large scale LNG terminals in operation in EU with a combined 

capacity of 195 bcm/y. Consequently, the average utilisation of the LNG import capacity is only 

around one third. 

Annual regasification capacity of large-scale
LNG import terminals per country

LNG import terminals offering reloading

billion m 3(N) / year

operational

under
construction

planned

Belgium
Croatia
Estonia
Finland
France
Greece
Ireland
Italy
Latvia
Lithuania
Malta
Netherlands
Poland
Portugal
Romania
Spain
UK
EU-28
Albania
Turkey
Ukraine
Europe

9

22
5

15

4

12

8

69
52
195

12

208

3
6
7
3
23
11
3
37
5

2
4
3

8
7
26
146
8
6
10
170

13
2

5

3

23

23

Number of LNG import terminals per type

operational

Large-scale

FSRUs and others

Small-scale
Total

24
3
4
28

under
construction
4
0
4
8

planned

22
7
4
26

Figure 3-18 European LNG import terminals – an overview 

The figure shows that most LNG regasification plants are located in Western and South-Western 

Europe, while there are few plants in Eastern Europe. More and more LNG plants have possibility 

for reloading, which means that LNG can be re-exported to destinations elsewhere globally 

37 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
An additional 23 bcm import capacity is at present under construction, mainly projects that were 

decided before the financial crisis and the following decline in gas consumption.  

The capacity of projects in Spain and Portugal is 77 bcm per year, which can be compared to the 

actual use in 2014 of around 16 bcm. The utilisation for these plants is hence only around 20 per 

cent. This opens for the possibility of using the terminals for import of gas for France and other 

parts of Europe, in particular when the import plants are fully utilised which is not the case at 

present. A large number of new LNG import terminals are planned, with most put on hold due to the 

lack of utilisation of existing plants.  

A main question for the additional interconnector capacity between Iberian Peninsula and the rest 

of Europe is if it will be more economical to develop new LNG facilities close to the end use market 

or to use the Spanish terminals combined with additional investments in pipeline and gas storage.  

The Dunkerque LNG plant in France is the largest ongoing expansion of LNG capacity in EU. With 

a capacity of 13 bcm/y, the plant may become an alternative to use of the UK and Spanish LNG 

import terminals. The investment cost is around [1250] MEUR. As this is the most recent green field 

project, the average investment cost of a new terminal can be assessed to around 100 

MEUR/bcm/y capacity.  

There are plans to expand the Fos-Cavaou LNG terminal with an additional 8.25 bcm/y. This will be 

an alternative to use the Spanish LNG terminals and transporting from Spain to France. The Fos-

Cavaou will also be an alternative to the North West European LNG terminals as the shipping 

distance will be shorter for gas arriving from Qatar. The expansion cost for the Fos-Cavaou is 

estimated by to 350 MEUR. Hereby, the marginal cost of expansion is less than 50 MEUR/bcm/y 

capacity. 

3.6

  EU security of gas supply – major cases and events 

3.6.1

  Disruption cases 

In the 2015 ENTSO-G TYDP report the focus is on the overall supply/demand balance and two 

specific cases for disruption:  

•  Disruption of Ukraine transit of gas from Russia 
•  Disruption of Belarus transit of gas from Russia 

ENTSO-G does not consider LNG supply disruption as a security of supply concern as it is 

assumed that the market will ensure supply from different sources, although at a higher price.  

The French N-1 criterion is disruption of the supply point from Germany Obergailbach. This implies 

disruption of gas supply from Russia. For Portugal the main criterion is disruption of supply to the 

LNG terminal in Sines for technical reasons or due to failure of the main supply countries Algeria or 

Nigeria. For Spain, Algeria constitutes a major risk.   

The following disruption cases have been identified as creating a supply situation where gas supply 

to Europe could benefit of having access to increased capacity between the Iberian Peninsula and 

the rest of EU.  

38 

 
 
 
 
 
 
 
 
 
 
 
 
For supply from South to North this includes: 

•  Russian disruption of gas supply or disruption of transit via Ukraine or Belarus or technical 

disruption of Nord Stream pipeline  

•  Norwegian technical disruption, in particular Troll or Sleipner fields or Draupner platform or 

Franpipe 

•  UK-Belgium interconnector failure – isolating UK from Continent as the BBL pipeline can only 

supply in one direction from The Netherlands to UK  

•  Groningen field decline in gas supply – escalation of earth quake problem 
•  Disruption of Algerian supply via Tunisia to Italy for technical or other reasons 
•  Disruption of Fos LNG import terminal in South of France 

On the demand side the following two events can be considered: 
•  Extreme cold weather in North and East Europe and consequently empty storage 
•  Nuclear incident in France, closing nuclear power and increase use of CCGT in France and 

Germany to maximum capacity for existing plants 

The sources of gas may differ in the specific cases depending on duration and time of the year. 

Initially it could be full use of the pipeline capacity via Medgaz and hereafter use of LNG or import 

via Maghreb-Europe pipeline.  

Technical fault on Medgaz, or Strait of Gibraltar pipelines/compressors 

From North to South the following events have been identified: 
•  Algerian gas supply disruption in general  
•  Qatar or Nigeria LNG failure – technical or other reasons 
• 
•  Morocco transit disruption  
• 
On the demand side the following event can be considered  
•  Sudden demand increase on Iberian peninsula (nuclear disruption, cold/warm weather, 

LNG accident in Spain 

combination) 

Some of these events will also impact the rest of EU, while some are specific for the Iberian 
Peninsula.  

In the following is given a more detailed description of cases with impact on the interconnection 

between Iberian Peninsula and the rest of Europe, 

3.6.2

  LNG supply disruption and reduction of supply 

As ENTSO-G does not include disruption or reduction of LNG supply in the TYDP report, it is worth 

to discuss this event in more details. Historical events which have disrupted LNG supply include a 

combination of political unrest, change in priority for resources and technical events:  

39 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Country 

Egypt 

Event  

Year and Duration  

Volume bcm/year 

Priority given to 

2012 - ongoing 

15  

indigenous use of gas 

after Arabic spring 

Yemen 

Civil war. Security and 

2014- ongoing 

attacks on pipelines 

Libya 

Civil war. Priority to 

2011- ongoing 

Algeria  

Explosion on LNG 

2004 - 2013 

pipeline supply 

 7 

5  

6  

liquefaction plant, 

Skikda 

Table 3-5 Historical events having disrupted LNG supplies 

This means that 3 out of 17 major LNG suppliers; Libya, Egypt and Yemen have stopped export 

during the last 5 years. Empirically this is a very high frequency, but it could be argued that the 

Arabic Spring was the root course for the events.  

Most important is the reliability of LNG supply from Qatar and Algeria. The probability of disruption 

of LNG supply from Qatar is a combination of technical and political factors. Different indices place 

Qatar as a political stable country, despite the fact that the last two emirs have come to power by 

bloodless coup. Technically, much of LNG from Qatar is shipped from Ras Laffan in the Northern 

part of the country. The probability of disruption is probably low, but as seen by the Skikda accident 

in Algeria, cannot be ruled out.  

3.6.3

  France – increase in demand due to nuclear incident  

Majority of electricity in France is produced on nuclear power plant. Hereby, there are some 

similarities between the energy system of Japan and France. The consequence of the Fukushima 

incident in Japan was that all nuclear power plants were closed for 4 years and only recently the 

first one was opened. 

Figure 3-19 French net generating capacity 2014 (MW) 

40 

 
 
 
 
 
 
 
Normally, gas for power generation in France is only used for approximately 1000 MW. In case of a 

nuclear incident it can be assumed that gas will be used for 10000 MW as base load. This will 

require about 50 mcm/day in additional gas consumption, or 15 bcm/y.  

The probability of the event is low. But with many nuclear power plants in France, the accumulated 

probability for an event on one plant will be higher than in most other countries. Historically there 

have been two main accidents internationally, out of approximately 200 power plants. 4 out of 

around 450 reactors have experienced melt down. So purely based on empirical statistics, globally 

there is approximately 1 per cent risk for a major (category 7) event during the entire life time of 

each reactor. .The risk in France is probably much lower, but it cannot be ruled out. Also, lower 

category events may create a public opinion which requires closing of some reactors. The 

probability of such events in France cannot be assessed in this study, although the events are still 

relevant.  

In the following we will use an event with additional 50 mcm/day gas consumption corresponding to 

around 15 bcm/year.  

3.6.4

  Tunisia as transit for gas from Algeria to Italy 

Tunisia is a transit country for all pipeline gas from Algeria to Italy. In recent years, the gas flow has 

been reduced. The capacity is up to 33 bcm/y 

Risk-wise Tunisia is ranked in different indexes on the same level as Belarus but better than Algeria 

and Russia in the following index from Fund for Peace. Recent events may increase the risk rating 

of Tunisia. 

The gas flow from Algeria to Italy has declined in recent years as Algeria has increased the flow to 

Spain via the direct Medgaz pipeline.  

Figure 3-20 Algerian pipeline gas exports to Europe 2006-2013 (Source BP Statistical Review 2014) 

41 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
In 2014 the gas transit via Tunisia was reduced to only 6.2 bcm. This could indicate that some gas 

may already have been re-directed to Medgaz or to LNG supply. Consequently, the consequences 

of a disruption will be in the order of 5 to 10 bcm/y which would need to be redirected.  

3.7

  Spain, Portugal and France demand and supply 

3.7.1

  Demand forecasts have been uncertain – create wrong signals and decisions 

Gas demand forecasts for Spain, Portugal and France have been uncertain in recent years, mostly 

because of the fluctuations in the use of gas for power generation in CCGT. This is caused by a 

combination of new sources of renewable, use of coal as gas prices became relatively high and 

less increase in electricity generation. Further, there have been large fluctuations in the climatic 

conditions which have impacted the use of gas in the power sector, as gas is mainly used as peak 

load.  

Figure 3-21 GDP growth, (Source:  IMF WEO data base April 2015) 

The long term development in GDP growth shows how severe the financial crisis hit Spain and 

Portugal with a double dip recession. France had avoided the double dip, but has in return been 

struggling to accelerate the economy. Due to general energy efficiency gains, the total energy 

consumption will need a GDP growth of around 2 per cent to create growth. As natural gas together 

with oil is marginal fuels, they will be even more sensitive to growth. This was the main reason for 

the decline in gas consumption during the financial crisis.  

Population growth is by itself an independent driver of energy and gas consumption. During the 

financial crisis, the population started to decline in Spain and Portugal as people migrated to other 

parts of EU and abroad. In France there is still a rapid growth, even though natural growth is 

combined with net emigration. In general there is a net long term migration from the East Europe to 

West Europe, also impacting the energy consumption. Recent migration from outside EU may also 

impact the demand outlook.  

Economic and population growth is extremely difficult to predict on the longer term. However, as 

most of Europe has a natural ageing with declining work forces, there is room for bounce back of 

the economy in South Europe with a large idle work force.  

42 

 
 
 
 
 
 
 
 
 
 
The figure below shows the sharp decline in gas consumption in Spain and a milder decline in 

France and Portugal. In particular the Spanish consumption is much lower than predicted before 

the financial crisis, which partly explains the decision to build many LNG terminals.  

Figure 3-22 Gas consumption, bcm/y (Source BP, 2015) 

The sharp decline in gas consumption in 2014 was due to a combination of extremely warm 

weather and high gas prices.  

3.7.2

  Gas demand forecasts Spain, Portugal and France 

Ramboll expects a recovery in the Spanish gas consumption as there is possibility for a bounce-

back effect. Our estimate is that the gas consumption will reach a plateau of 40 bcm. This is in line 

with ENTSO-G two scenarios. However, we foresee that a very high focus on climate issues may 

hurt gas consumption as Spain has tradition and space for wind power and also for solar energy. 

However, at present the development of wind power in Spain is very slow. 

We foresee an increase in natural gas consumption in Portugal to between 6 and 8 bcm per year. 

This is in line with ENTSO-G scenarios between 8 and 9 bcm/y. Portugal has been particularly hard 

hit by the financial crisis and the decline in population. There is hence good potential for recovery. 

The conditions for increased use of renewable imply that extreme focus on climate issues may hurt 

gas consumption.  

Our scenario for France depends very much on the use of nuclear power and use of renewables. 

We foresee gas consumption between 40 and 55 bcm/y in 2035 under the present assumptions 

and use of nuclear and renewables, depending on economic growth. This is in line with ENTSO-G 

scenarios. However, as France has amble possibilities for wind, solar and bio energy we foresee 

that it will be the green focus which will result in lowest gas consumption. An extreme focus on 

climate change and renewables can bring gas demand further down than described above. The 

extreme high use of nuclear power in France gives the risk of rapid changes, if new political 

decision is made to reduce use of nuclear energy. This could be due to accidents or cost. In such 

scenario, the gas demand may increase up to same level as seen in UK, Germany and Italy of up 

43 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to 80 bcm/y. To reach such level it will be necessary to construct new CCGT power plants. The 

total LNG capacity can cover a large part of such increase in demand.  

France still has a very low gas consumption per capita compared to other countries. It cannot be 
ruled out that there will be a rapid increase in gas consumption as more CCGTs are being built. 
Also, large fluctuations can be expected from year to year due to use of weather conditions and use 
of renewables.  

3.7.3

  Supply – sources and concentration  

The concentration of suppliers is to a certain degree determined by the physical possibilities for 

import. Below in Figure 3-23 the concentration calculated as the herfindahl-hirschman index, which 

is a general methodology for measure of competition, on the imports from the period 2005-2013 is 

presented, with the exporting country as a proxy for the supplier. It shows that the concentration of 

imports in Spain has increased over the past 4 years. The concentration has increased in France. 

While Portugal, although having a much higher concentration of importers, has seen a larger 

diversity in suppliers since 2005.    

Figure 3-23 Gas market concentration South-West Europe by supply countries Source: Eurostat 

Spain has traditionally received most gas from North Africa, initially from Libya, later on from 

Algeria. Further, Spain was pioneer to develop the global LNG market. At present there are many 

suppliers also from South America and Sub-saharan Africa.  

Norway is an important gas supplier with more than 3 bcm/y as part of the Troll agreement. 

44 

 
 
 
 
 
 
 
 
 
Figure 3-24 The Spanish and Portuguese natural gas network (Source: Entso-G) 

Most gas to Portugal was originally supplied via Spain with the construction of an interconnector 

pipeline as part of the Maghreb-Europe system. Later one additional interconnector has been 

established and an LNG import terminal in Sines with a capacity of more than 5 bcm/y.  

France has a diversified system and most gas is supplied by pipeline from Norway and from 

Russia. Further, gas is supplied by pipeline from the Netherlands via Belgium, some as low calorific 

gas. LNG is mainly supplied from Algeria, Nigeria and Qatar. Some of this supply is associated with 

suppliers participating in upstream activities in particular in Nigeria.  

In the overall French gas balance it is assumed that there will be high flow into the system from 

Norway in Dunkerque as there is insufficient capacity in the Norwegian system to move gas to other 

points. The minimum expected input from Norway is more than 10 bcm as Norway would otherwise 

have to reduce production from their offshore fields.  

45 

 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-25 The French natural gas network (Source ENTSO-G) 

The French system uses odorisation in the gas transmission system, while Germany has 

odorisation in the distribution system. This means that it is not at present possible to have physical 

flow from France to Germany. However, a new pipeline has been constructed to connect France 

and Belgium allowing for flow of gas before odorisation.  

The overall balance of the French gas transmission system is shown below.  

46 

 
 
 
 
 
 
 
Figure 3-26 The French gas system - overall balance (bcm/y) 

Import from Dunkerque via Franpipe is assumed to be fixed as there is no alternative possibility for 

export of Norwegian gas with the present Norwegian system.  

With maximum use of the LNG import facilities, there will be surplus capacity for the Grey demand 

scenario, without import from Germany (Russia) and Belgium (The Netherland, Norway or UK). 

In the Green demand scenario, there will be space for more than 5 bcm even in a situation with 

maximum use of the French LNG import. Hence, the demand situation in France is important for the 

possible use of interconnector from Iberian Peninsula.  

3.8

  Gas prices and contracts  

Different gas prices, transportation fees and contractual obligations are influencing the physical and 

contractual flow of the gas transmission systems. Some of these prices are publically available, 

while some are kept confidential such as long term gas supply contracts including indexation and 

take-or-pay obligations.  

Natural gas prices internationally diverged from 2010 due to oversupply of shale gas in USA and 

from 2011 due to the Fukushima nuclear accident in Japan. From 2014, the difference between 

Asian and European prices disappeared to converge fully in 2015. However, still more than the 

double of US prices.  

47 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 3-27 International gas prices – comparison and impact (sources: Platts, Thomson Reuters, 

BAFA) 

Without difference between Asian and European prices, it is more likely that gas LNG will be 

shipped to Europe.  

The spot prices for gas in EU are shown below. The high Spanish LNG prices is one reason for low 

utilisation of the Spanish LNG terminals and net flow from France to Spain.  

Figure 3-28 Landed prices for LNG (source: Platts, Thomson Reuters, European Commission) 

48 

 
 
 
 
 
 
 
 
 
 
 
Figure 3-29 Energy prices converge in South Europe  

From mid-2015 the prices converge in South Europe. One of the consequences has been that the 

net flow in the interconnector between Spain and France has been reduced.  

49 

 
 
 
 
 
 
 
 
 
 
4  Transportation tariffs  

4.1

  French regulated transportation tariff overview and comments 

4.1.1

  Overview  

The tariff system in France is based on an entry exit system with regulated tariffs as basis. The exit 

points to the system are located on the borders. The system is divided into two transmission 

systems, GRTGaz and TIGF. With respect to transmission tariffs the system is divided into a North 

and a South zone, where the South zone from 2015 is merged between GRTGaz Sud and TIGF. It 

is planned that entire France will be merged into one zone from 2018.  

The entry points to the French system are pipeline connection points from Norway, Belgium, 

Germany and Spain. From 2018 there will also be an entry point from Switzerland when the TENP 

system will have reverse flow capability and open for delivery of gas from TAP via Italy.  

The exit points are towards Switzerland and Spain. From 2015 there will further be an exit point 

towards Belgium to be used for gas from the new Dunkerque LNG terminal and Franpipe, before 

adding odorant. The policy for odorisation is the reason why there is no exit possibility towards 

Germany. There are no direct connections between France and Italy.  

At some entry and exit points it is possible to have reverse flow. The general tariff for reverse flow is 

20 per cent of forward flow, except for the new connection to Belgium in Alveringem.  

50 

 
 
 
 
 
 
 
 
 
 
 
 
The tariffs are as follows for yearly products:  

Point for entry 

Country 

Entry/exit 

Tariff  

Interruptible 

EUR/MWh/day/year

coefficient  

or exit of gas 

Taisnières B 

Taisnières H 

Taisnières H 

Dunkerque 

Obergailbach 

Obergailbach 

Montoir 

Fos 

Belgium 

Belgium 

Belgium 

Norway 

Germany 

Germany 

LNG 

LNG 

Dunkerque GNL 

LNG 

Entry 

Entry 

Reverse flow 

Entry 

Entry 

Reverse flow 

Entry 

Entry 

Entry 

Exit 

88.82 

114.19 

22.838 

114.19 

114.19 

22.838 

107.84 

107.84 

107.84 

398.39 

Oltingue 

Oltingue 

Oltingue 

Jura  

Jura  

Alveringem 

Alveringem 

PIRINEOS 

PIRINEOS 

North to South 

South to North 

Exit main 

network 

Switzerland 

Switzerland 

Reverse flow  

79.678 

Switzerland 

Switzerland 

Entry 

Exit 

From 2018 

98.61 

Switzerland 

Reverse flow  

19.722 

Belgium  

Belgium  

Spain 

Spain  

France 

France 

France 

Exit 

Reverse flow 

Entry 

Exit 

Exit 

45.00 

56.25 

114.19 

496.39 

208.04 

50.00 

93.75 

50% 

50% 

50% 

50% 

N/A 

N/A 

N/A 

75% 

75% 

N/A 

75% 

75% 

50% 

50% 

50% 

Table 4-1 Entry and exit tariffs in France 2015 

For monthly and daily products there are different rules. In general, the monthly entry tariff is 1/8 of 

the yearly tariff, this is also the case for the PIRINEOS, the interconnection point between France 

and Spain. For exit from the main network, the monthly tariff depends on the season with the 

highest payment during winter.  

4.1.2

Impact of establishing one zone in France from 2018 

The French gas transmission system will be unified into one zone from 2018. This will most likely 

result in an increase in the border tariffs for the exit to Spain.  

The French regulator will start a process to establish the future tariffs, but the process is only being 

started. A future network code is expected in 2017.  

One of the main issues is the allocation of cost for new infrastructure. As an example, the Eridan 

pipeline was assumed to be split equally between the North-South merger and the Midcat during 

the open season in 2010. Now the regulator assumes that the full cost is allocated to MidCat, as it 

has not been found necessary to establish the Eridan project as part of the creation of one zone. 

51 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.1.3

  Assessment of French transmission system  

The French tariff system is a pure capacity based system. The tariffs system has an almost uniform 

entry tariff from pipelines and LNG for firm capacity. However, for interruptible capacity the 

PIRENEOS tariff is higher than for others as the factor on firm capacity is 75%, while it is 50% for 

other entry points. This means that the tariff for interruptible capacity is quite high which may hinder 

use of capacity.  

For exit tariffs the PIRENEOS has by far the highest tariff, which is around 400 EUR/MWh/day/year 

higher than delivery to exit points inside France and for delivery to the Jura exit point towards 

Switzerland. This is a substantial difference, which with a constant flow results in transportation 

tariff of more than 1 EUR/MWh. If only monthly products are used with a load factor of 50%, the 

transportation cost will be more than 3 EUR/MWh.  

As the historical gas transmission via the PIRENEOS has been from North to South it could be 

argued that the reverse flow tariff used for other entry points of 22,838 EUR/MWh/day/year should 

be used at this point instead of the normal entry tariff of 114,19EUR/MWh/day/year. This would 

make it more attractive to import gas from Spanish LNG plants and pipeline towards France, and 

hence also reduce the congestion in the French system.  

The tariffs for using the Iberian pipelines in the French system are clearly very high as compared to 

use of the system for ingenious use, and the system hereby counteracts the use of the 

interconnectors.  

The French system is very large with few entry and exit points towards neighbouring countries and 

limited transit volumes. The gas consumption per area is low compared to countries like the 

Netherlands, Belgium, Italy and UK. With a wish to create very large exit zones, only two zones 

from 2015 and only one zone from 2018, there will be cross subsidies among gas consumers. If the 

same principles are used when the one zone principle is introduced in 2018 there may be even 

higher barrier for use of the Iberian pipelines than today.  

The entry-exit system of France will by far be the largest in the EU in terms of area. Although the 

ultimate goal of the EU may be to create a single zone, it is well known from the literature that very 

large entry-exit zones may create problems. Reference can be done to a recent paper by Dr. 

Harald Hecking http://www.naturalgaseurope.com/images/ewi%20Policy%20Brief%20-

%20Rethinking%20entry%20exit.pdf 

When long-term bookings have been made for gas transmission, the shipper may choose only to 

make a short term marginal cost consideration, at least when he has spare capacity. However, 

there is no reason for him to do so if competitors have to book short term capacity at a higher cost.  

To our knowledge correct that the unified French gas transmission system will be in accordance 

with the European Gas Target Model (EGTM). However, it should be kept in mind that EGTM also 

says that “As a general rule, entry-exit zones should not be defined on the basis of national 

boundaries, but based on physical realities and market needs.” 

In “Network Code on Harmonised Transmission Tariff Structures for Gas” July 2015, it is as a 

general rule said that “Where the entry-exit split is used as a parameter of the reference price 

methodology, it shall be equal to 50/50, unless otherwise set or approved by the national regulatory 

authority”.  

52 

 
 
 
 
 
 
 
 
 
 
 
 
4.2

  Spanish regulated transmission tariffs overview and comments  

The Spanish gas transmission system is an entry exit system with regulated tariffs. The tariffs were 

most recently updated in 2014 and no update took place in 2015.  

Figure 4-1 Spanish gas transmission system (Source: Enagas) 

The main entry points to the system are the Tarifa and Almeria pipeline with gas from Algeria and 

the VIP PIRENEOS (Larrau and Irun pipelines) from France and the six LNG terminals. There are 

exit points to Portugal, where the most important is Badajos and the northern point of Tuy, 

regulated as a virtual exit point VIP Portugal.  

The entry tariff is 1.0848 cent/kWh/day/month Gas in kind (applied at entries): 0.2%. If we 

recalculate this to the same unit as for the yearly capacity used in France, this will with a load factor 

of 100 per cent be 130 EUR/MWh/day/year plus a commodity charge of 0.2%. 

For the export there is a capacity element of 2.0060 cent/kWh/day/month and a commodity term 0 

cent/kWh, which corresponds to 240,72 EUR/MWh/day/year. For export there are special 

favourable conditions with a factor 0.7 on the normal exit tariffs and zero commodity charge. The 

normal exit conditions for systems with a pressure above 60 bar are 2,8658 cent/kWh/day/month 

plus a commodity charge of 0,0615 cent/kwh, corresponding to 343,9 EUR/MWh/day/year plus 

0,0615 cent/kwh.  

The Spanish tariff system with only one zone has the same problem as the French system; that a 

very large zone will give relatively high entry and exit tariffs to the system. The Spanish system has 

given some incentives to export by having a factor of 0.7 on the export and no commodity charge.  

The entry tariff to Spain is a little higher than the corresponding French tariff, while the exit for 

export is substantially lower than the French tariff.  

53 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.3

  Tariff barrier for use of interconnection between Spain and France 

To illustrate the tariff barrier for use of the interconnector between Spain and France, a number of 

calculations have been made for firm capacity: 

-  Supply of gas from Northern Europe with pipeline entry into France to and including exit 
from the main transmission system in respectively TIGF area and in Spain and including 
regional transmission and delivery 

-  Supply of gas from Algeria with pipeline entry into France to and including exit from the 
main transmission system in respectively TIGF area and in Spain and including regional 
transmission and delivery 

-  Supply of gas from respectively LNG terminals in France and Spain to and including exit 

from the main transmission system in TIGF area 

The main results for a load factor of 100 per cent are as follows: 

Capacity
Capacity
cent/kwh/day/moEUR/MWh/day/yea percent 

Commodity

Entry France - pipeline
North-South
Exit PIRENEOS, France
Exit Spain 
Entry PIRENEOS, France
Entry Spain 
Exit main system TIGF
Regional transmission 
Delivery, France 
Exit main system Spain (1.3)

Total
Per MWh

114,190
208,040
496,390
240,720
114,19
130,176
93,750
62,740
23,690
343,884

2,0060

1,0848

2,8657

Transport of 1 MWh/day, 100% load factor

EURO/MWh France-Spa France-FranSpain-SpainSpain-Franc
114,190
208,040

114,190
208,040
496,390

0,00%

0,0000

0,20%

0,0400

144,776

144,776

93,75
62,740
23,690

240,720
114,19
144,776
93,75
62,740
23,690

0,615

568,359

568,359

1531,755
4,20

502,410
1,38

713,135
1,95

679,866
1,86

Table 4-2 Transportation tariffs for delivery to Spain and France for pipeline supply (Source: own 

calculations) 

Entry France LNG
Entry Spain 
Entry PIRENEOS, France
Exit Spain 
Exit main system TIGF
Regional transmission 
Delivery, France 

Total
Per MWh

Capacity
Capacity
cent/kwh/day/moEUR/MWh/day/yea percent 

Commodity

Transport of 1 MWh/day, 100% load factor

EURO/MWh South LNG Spain LNG

107,840

1,0848

2,0060

107,84
130,176
114,19
240,720
93,750
62,740
23,690

0,20%

0,0400

0,00%

0,0000

144,776
114,19
240,720
93,75
62,740
23,690

93,750
62,740
23,690

288,020
0,79

679,866
1,86

Table 4-3 Transportation tariffs for delivery in France from LNG terminals in respectively France and 

Spain (Source: own calculations) 

This high exit tariff from France at PIRENEOS result in a tariff difference for pipeline gas delivered 

from respectively France and Spain in Spain of 2.25 EUR/MWh. In the opposite direction, the 

difference is smaller 0.48 EUR/MWh.  

For LNG delivery from regasification plants in respectively Spain and France, the difference in 

tariffs is 1.07 EUR/MWh. Here the difference in regasification itself has not been included.  

The high tariff in particular from French to Spain creates a competitive advantage for e.g. industrial 

users north of the border, who will receive indirect subsidies from other French consumers due to 

the large zones. With unification of the French system this will be even larger. The high tariff from 

France is reflecting the cost of long transportation distance from the Northern entry points in 

Northern France 

54 

 
 
 
 
 
 
 
 
 
 
 
 
4.4

  Auctioning of capacity, CAM, Capacity Allocation Mechanism 

In addition to the regulated tariffs there will be auctioning according to the EU CAM rules which 

officially came into force from 1 November 2015. According to the CAM rules, bundled capacity will 

be offered at the border point securing access on both sides of the border. Auctioning will be held 

for yearly, quarterly, monthly, daily and within-day products. The payment of transportation will be 

the regulated tariffs plus the result of the auctioning.  

4.5

  UBI (Use-it-and-Buy-It) capacity offer 

According to TIGF “The “Use-It-and-Buy-It” (UBI) offer allows a Shipper to request additional 

capacities over and above its subscriptions (firm and interruptible). These capacities can be 

allocated to it (in whole or in part) if another Shipper does not use all of its capacities on a given 

day.” UBI is only offered in the forward direction of the PIRENEOS border point from France to 

Spain and not in the opposite direction.  

4.6

  Use of gas storage in South of France for Spanish gas 

Spain has only very limited gas storage of 2.5 bcm, while France has more than 12 bcm of storage 

facilities. It would hence be obvious to use the large storage in the TIGF area in France for storing 

Spanish gas.  

However, the average cost of crossing the border from south to north during injection and from 

north to south during withdrawal adds up to very high level depending on the actual use.  

With a load factor of 50 per cent, which is high, this would add up to more than 5 EUR/MWh.  

Entry PIRENEOS, France
Exit Spain 
Exit PIRENEOS, France
Entry Spain 

Total
Per MWh
Load factor 50%

Capacity
Capacity
cent/kwh/day/moEUR/MWh/day/yea percent 

Commodity

EURO/MWh Withdrawa Injection

2,0060

1,0848

114,19
240,720
496,390
130,176

0,00%

0,0000

0,20%

0,0400

496,390
144,776

114,19
240,720

641,166
1,76
3,51

354,910
0,97
1,94

2,73
5,46

Table 4-4 Tariff calculations for use of gas storage in South of France from Spain 

4.7

  Enagas examples on impact of LNG terminal and transportation tariffs 

Enagas has carried out a number of calculations of transportation tariffs and use of LNG terminals 

in respectively France and Spain. One example for supply to the TIGF area is shown below. It can 

be seen that it will be cheaper to supply gas from the French LNG terminals than from Spanish 

terminals due to the transportation tariffs, even though Spanish LNG terminals are cheaper than 

French terminals.  

55 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 4-2 Tariff calculations for delivery in south-west of France from different delivery points in 

France and Spain, including LNG regasification – (source: Enagas) 

The example also illustrates that is may be an advantage to reload LNG from Spanish terminals 

rather than to use the pipeline systems, even as reverse flow.  

4.8

  Conclusions on tariffs 

- 

The present tariff system in France and Spain constitutes a major barrier for transportation 
of gas and creation of competitive market for gas on the Iberian Peninsula 

o  The transmission tariffs with high cost for crossing the border from France to 
Spain creates a barrier for transportation of gas from North to South and 
consequently there will be impact on the price formation.  

o  The south-north tariffs are establishing cost differences for import of LNG from 
Spanish and French LNG terminals and may hereby limit the transportation 
across the border from south to north. This is one reason for bypassing Iberian 
LNG terminals. 

o  Use of gas storage in South of France for Spanish LNG is made impossible due 

to the transportation tariffs across the border 

- 
- 

The one zone policy in France will further increase the border tariffs  
The tariff system result in competitive advantage for e.g. industrial users north of the 
border as compared to Iberian users during situation with flow from North to South, which 
has been the situation for the last years.  
Tariffs for interruptible capacity across the border between France and Spain have a 
smaller rebate than for entry tariffs and for exit tariffs from the main system in France.  
-  Possibility for an integrated entry-exit system between France, Spain and Portugal should 

- 

be evaluated to create full integration. 

56 

 
 
 
 
 
 
 
5 

Interconnectors – identifications and 
technical solutions 

5.1

  Technical solutions for additional interconnectors  

The present chapter describes the identified technical solutions for additional interconnectors 

between the Iberian Peninsula and the rest of Europe. During the inception phase, it was decided to 

focus on the already identified projects as described in the open season in 2010. Focus of the 

description is to identify cost and time as input to the cost benefit analyses and comparison of 

technical solutions.  

The basis for the description is a shared technical report between the three gas transmission 

companies Enagas, TIGF and GRTGaz. In addition, Ramboll has made own technical estimates, 

but no full pre-feasibility for the identified projects have been made by the promoters. The shared 

study has been made based on already existing technical solutions, which in some cases are back 

to 2010. Consequently, there is a need for updating such work with respect to technical solutions, 

environmental impact and authority approval.  

Eventually the goal with increased interconnector are to be able to transport gas from the LNG 

terminals and pipelines in Spain to France and further on to Germany and Central European 

countries, which are now depending on import of Russian gas without direct access to the global 

LNG market and to transport gas from the integrated EU gas system to Spain and Portugal and 

hereby integrate these two countries fully into the EU system.  

5.2

  Existing interconnectors between Spain and France and agreed network 

additions 

At present there are two pipeline interconnectors between France and Spain:  

- Larrau, DN650 mm pipeline (26”) with a design pressure of 80 bar 

- Biriatou, DN600 mm pipeline (24”) with a design pressure of 80 bar 

57 

 
 
 
 
 
 
 
Figure 5-1 Existing pipeline interconnectors with indicative route for MidCat first phase  

The combined capacity of the two pipelines are 170 GWh/d (14.8 mcm/d) from Spain to France and 

165 GWh/day (14.3 mcm/d) from France to Spain. From 1 December 2015, the capacity was 

increased to 222 GWh/day from Spain to France. The first pipeline was built back in 1990´ies to 

transport gas from Norway to Spain under the Troll agreement.  

Gascogne-Midi project  

It has been decided to strengthen the connection by the Gascogne-Midi project, with TIGF as 

promoter.  

Figure 5-2 Prospective development programme for TIGF's gas transmission network 2014-2024 (source 

TIGF) 

After the implementation of this project the capacity of the existing pipelines can be increased and 

there will be more flexibility between West and East of France, which may also impact possible 

solutions for strengthening of the French gas transmission system.  

58 

 
 
 
 
 
 
 
Merger between North and South Zone in France – Val de Saône pipeline 

The merger between the North and South zones in France is on-going by establishing the Val de 

Saône pipeline.   

The project consists in the looping of the Burgundy pipeline (189 km, DN 1200) between Etrez and 

Voisines in Eastern France. The cost of the pipeline is estimated to 744 million EUR, corresponding 

to an average cost of almost 4 million EUR per km, illustrating the relative high pipeline construction 

cost in France. 

Figure 5-3 Val de Saône pipeline (Source GRTGaz and Ramboll) 

The project is now being approved by authorities, and it is assumed that the pipeline will be 

constructed during 2015 and 2016 and taken into operation in 2017. 

5.3

  France-Spain interconnector - Eastern corridor - definitions  

5.3.1

  MidCat definitions  

An eastern corridor has been evaluated for decades between France and Spain. Initially this goes 

back to the development of the Maghreb-Europe pipeline from Spain in the early 1990´ies. In recent 

years, the MidCat name has been used for this pipeline although the definitions have not always 

been clear.  

In the regional development plan GRIP 2010 report the following definition was used: “The MidCat 

Project involves the development of a full corridor (Eastern) between Spain and the North of 

France, by the association of a new interconnection point (Le Perthus sub-project), the GRTgaz 

South-TIGF subproject and the expansion of the interconnection capacity between GRTgaz North 

and GRTgaz South (GRTgaz North-GRTgaz South subproject).” 

In 2015 the three companies Enagas, TIGF and GRTGaz carried out a common study for the 

MidCat project. Here two steps were considered:  

•  MidCat first step 
• 

Full MidCat 

59 

 
 
 
 
 
 
 
 
 
 
 
 
 
The following parts were included in the definitions. 

Figure 5-4 The full set of infrastructures as defined by the TSOs in the context of the study (source: 

Joint Technical Study Between ENAGAS, GRTgaz and TIGF) 

The table illustrates the pipeline dimensions in mm, operational pressure in bar and power of the 

compressor stations in MW. Further cost estimates are included for some sections.  

It can be seen that the first step of the pipeline will only include the 224 km long section from 

Hostalrich via Figueras to the border and further to the compressor station in Barbaira close to 

Carcassonne.  

The other parts of the project as defined in the table partly have as an objective to transport gas 

from/to the interconnector partly other purposes such as generally develop the gas systems in the 

two countries. 

In the shared report the following influence zones are given together with possible pipeline routes in 

France and Spain. However, other alternative routes are also possible.  

60 

 
 
 
 
 
 
 
 
 
Figure 5-5 Zones of influence of the MidCat project in Spain and France according to the understanding 

of each TSO, and the phased infrastructures considered (source: Joint Technical Study Between 

ENAGAS, GRTgaz and TIGF) 

The original definition of MidCat goes back in time and may create misunderstandings among 

stakeholders and uncertainty about technical solutions, purpose and cost. This is because some of 

the elements of the original definition have already been implemented. Further elements like Eridan 

pipeline can be used together with the interconnection to Spain, but as well to supply South Eastern 

France instead of supply from LNG terminal. Also, more options are possible for transportation of 

gas from South to North of France, and for the one shown above there is only one possibility. No 

detailed routing for the first phase has been made available.  

We will therefore recommend renaming the pipeline and defining the first stage of MidCat without 

necessarily using the original capacity, size or routing. To make the project easily understandable, 

we suggest renaming the section with a unique name which can be understood by stakeholders 

and the public: Girona-Carcassonne gas interconnector.  

61 

 
 
 
 
 
 
 
 
 
 
5.3.2

  MidCat – first phase – Girona-Carcassonne  

MidCat First phase – Girona-Carcassone – description and assessment  

In the joint study between Enagas, TIGF and GRTGaz the following elements are included in the 

project:  

On the French side, a 120 km long pipeline between the existing compressor station of Barbaira, 

close to Carcassonne, and Le Perthus at the border to Spain. On the Spanish side the MidCat 

consists of a 104 km pipeline between Hostalric, south of Girone, via Figueras to Le Perthus, and a 

36 MW compressor station in Martorell close to Barcelona.  

Figure 5-6 First step MidCat – (source: Joint Technical Study Between ENAGAS, GRTgaz and TIGF) 

The pipeline diameter is 900 mm, which is a medium size transmission pipeline with a design 

pressure of 80 bar similar to the design pressure of adjacent pipeline systems in France and Spain.  

The costs of the pipelines are estimated by the two TSOs; TIGF on the French side and Enagas on 

the Spanish side to 429 MEUR and further 42 MEUR for the compressor station. Review of the cost 

estimates is ongoing.  

The route selection, dimensioning and cost estimation is based on existing information carried out 

by Enagas and TIGF as part of an open season 2010 project. Optimisation of dimensions and 

alternative routing, including offshore, has not been carried out. 

TSO 

No  Component 

Diameter/Power  Pressure 

Length 

Cost 

TIGF 

Enagas 

Enagas 

8 

Barbaira-Border 

DN900 

11 

Figueras-Border 

DN900 

12  Hostalrich-

DN900 

Figueras 

Enagas 

13  Compressor 

36 MW 

(bar) 

80  

80 

80 

80 

120 km 

25 

79 

(MEUR) 

320 

29 

81 

42 

472 

Table 5-1 First phase of infrastructure, MidCat Girona-Carcassonne 

It has not been possible to obtain detailed routing of the pipeline as only preliminary studies have 

been performed to the identification of several alternatives. Additional field work and analysis need 

62 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to be conducted in order to select the final route. Also, the cost estimates are based on work done 

before the open season in 2010 and has not been updated as part of the shared study.  

On the French side, the route may include crossing of wine yards and is exposed to severe 

environmental constraints. This may impact the cost of the pipeline.  

It is Ramboll´s assessment that the cost estimates for the pipeline is very high on the French side, 

which may be because of cost or right-of-way. On the Spanish side, the cost seems to be very low. 

As can be seen from the table above, the average cost per kilometre of pipeline varies between 2.7 

MEUR in France and 1.0 MEUR/km in Spain. The difference in terrain should not justify such large 

difference in cost. Also, the cost of the compressor station in Spain seems low. This demonstrates 

that additional technical maturing of the pipeline system is necessary. This should also include a 

unified approach to cost estimation.  

Capacity share study by Enagas, TIGF and GRTGaz 

Whereas the infrastructure of the MidCat first phase is located entirely on the territory of 

respectively Enagas in Spain and TIGF in France, the capacity will also depend on the conditions of 

the GRTGaz system in France.  

The available capacity will depend on the climatic conditions and hereby indigenous gas 

consumption, use of gas fired power plants (Combined Cycle Gas Turbines), underground gas 

storage injection and withdrawal levels and input from LNG terminals and pipelines. Some of these 

parameters are natural variations, while some are market based.  

For assessing the capacity, a number of scenarios were developed. For climatic conditions this 

included a peak demand (defined as the coldest day in 20 years in Spain, respectively 50 years in 

France) and average winter and average summer conditions. For use of CCGT it includes use of 

50% of the French plants and in Spain a number of plants used to meet climatic conditions.  

For the output from underground gas storage and LNG plants there are favorable and unfavorable 

patterns for the increased interconnector capacity. As an example, high flow on the interconnector 

from Spain to France simultaneous with output form underground gas storage and LNG in South of 

France will create bottlenecks in the French system. On the other hand, such a flow pattern will 

require input from LNG plant in Barcelona in Spain. For some unfavorable cases there will be no 

available capacity.  

The shared study was based on peak demand, average winter climate and average summer 

climate, respectively. In the study, a best and worst case analyses were made, resulting in full 

capacity of the pipeline or zero capacity, respectively. Further intermediate assumptions or 

conditions were made. This can be summarised as shown in the table below: 

Spain to France 

France to Spain 

GWh/day 

Best case 

Worst case 

230 

0 

Intermediate case 

120 

245 

0 

80 

Table 5-2 MidCat capacity under different assumptions first phase (Source: Shared study) 

63 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
The capacity for the intermediate case for first phase in the shared study is 120 GWh/day (10.5 

mcm/day) from South to North and 80 GWh/day (7 mcm/day) from North to South. This capacity 

has been identified as capacity based on bottlenecks and assumptions for future use of the existing 

and planned systems, including the following conditions for flow from Spain to France:  

-  Barcelona LNG to supply at least 63 % of capacity in peak demand and 25% during 

- 

average winter conditions 
Limitation of output from Fos LNG terminal in France, Lussagnet and Mansque 
underground gas storage to less than 75% of their nominal capacity in summer situation 
during injection.  

To meet the capacity of 80 GWh/day from France to Spain there may be congestion at the entry of 

the network in the North of France. This will in particular be the case during summer, when there is 

only a very small consumption along the network in France and when there is high injection to gas 

storage. Here the use of MidCat will compete with capacity for filling underground gas storage in 

the south. The following conditions need to be met:  

-  Balanced entry to France from North (Germany, Belgium and Dunkerque) with entry into 

the LNG terminals Fos and Montoir, or 

-  Reduction of injection in the underground gas storage of Lussagnet, Manosque and 

Chemery to less than 58 per cent in case of no input from Fos, as compared to a limitation 
of 71% without the MidCat, or 

-  Barcelona LNG to supply less than 95% of nominal capacity  

Technically, the ultimate capacity of the pipeline will be around 230 GWh/day (20 mcm/day), if there 

was sufficient capacity of the gas networks and compressors in France and Spain.  

Furthermore, Enagas has carried out probability analyses of their system showing that probability to 

reach the 120 GWh/day is more than 98 per cent, while the full capacity of 230 GWh can be 

achieved for more than 80 per cent of the time. This means that the full capacity may be available 

as interruptible capacity even without investing in the further strengthening of the systems in Spain. 

The probabilistic calculations are based on historical data for use of the Spanish system. The 

analyses showed that the scenarios used in the shared study were very conservative.  

On the French side it has not been possible to do similar probabilistic simulations as the conditions 

will change as part of the unification of the system and the implantation of new infrastructure. The 

main uncertainty about capacity is hence on the French side of the interconnector. This will be 

further discussed and analysed in the final report.  

Capacity calculations comments and proposed additional analyses 

The methodology and the assumptions used in the shared study are deemed by the TSOs to be 

quite conservative. We agree with this conclusion and the large variation shown between best and 

worst cases show that there is a need for more technical clarity and loosening of some of the 

constraints to fully use the capacity.  

Our main comments to the assumptions and scenarios are: 

- 

The scenarios and climatic conditions used are very conservative. By only assessing the 

peak winter day, average winter and average summer conditions only a small part of the 

year is covered. The spring and autumn seasons are not covered at all and it may be that 

there is most flexibility in the use of the European gas system, depending on the actual 

use of storage etc.  

64 

 
 
 
  
 
 
 
 
 
 
 
- 

The peak winter condition is defined differently in Spain, one in 20 years, and France once 

in 50 years. This implies that higher priority is given to supply in France than to the 

interconnector points. The choice of probability is a political issue, but in this case it gives 

higher security of supply for France than for other countries. We will recommend reviewing 

the peak demand cases to identify additional capacity not least in view of the recent years’ 

warmer climate.  

- 

The use of CCGT is treated differently on the French and Spanish side. In France an 

average use of 50 per cent of the CCGT is assumed. This seems to be rather arbitrarily 

and does not reflect the dynamics of the electricity market. 

-  No link has been established between the use of CCGT and injection and withdrawal from 

storage. In practise there will be less injection in storage if CCGTs are used or higher 

withdrawal. It does not seem as if correlation between storage use and CCGTs are used in 

the calculations.  

-  Simultaneous use of gas storage and interconnector is used in the calculations. This will 

most likely not be the case in practise.  

- 

The conditions for use of existing UGS and LNG give priority to these facilities over the 

interconnector. As an example in the summer case it is assumed that there will be full 

injection in gas storage in South of France. However, the overall market incentives for use 

of the interconnector may be situations where the storages are already full. The actual use 

of storage and LNG facilities are not used in analyses only the capacities. We would 

recommend using hindcast analyses on how they have been used in the past, adjusted for 

the creation of one zone in France from 2018. This will allow for a probabilistic approach 

rather than the deterministic used in the shared study. Enagas has performed such 

analyses on the Spanish side. We would recommend doing the same on the French side.  

Sensitivity of cost and capacity to pipeline diameter 

One of the basic fundaments of pipeline design is the strong economics of scale. In the present 

case it seems as there will be large costs connected with right-of-way in France due to crossing of 

wine yards, complicated environmental constraints etc. Such cost will be (almost) independent of 

pipeline dimensions. This will also be the case for design and supervision. The main difference in 

cost will hence be steel material and excavation as well as pipeline transport and installation.  

The cost of a DN1200 pipeline compared to a DN900 is estimated to be roughly proportional to the 

diameter, which means that the cost will be around 33% higher for the DN1200. The technical 

capacity of a DN1200 is more than the double of a DN900 pipeline - an increase of approximately 

110 per cent.  

The marginal cost of transportation of gas in a DN1200 versus a DN900 pipeline is hence only 30 

per cent of the cost of a DN900 pipeline. Therefore, it should be considered to establish a large 

diameter pipeline for the first section.  

MidCat - First phase - Girona-Carcassonne – offshore alternative  

The initial cost indication from the French part of the first phase from Barbaira to the border is very 

high due to environmental constraints and compensation to landowners.  

As an alternative to the traditional crossing of the eastern part of the Pyrenees with wine yards, it 

could be considered to choose an offshore pipeline for a certain section. Examples of such 

solutions are shown on the map below, also indicating that the water depth is not a problem. The 

main problem would be the landfalls.  

65 

 
 
 
 
 
 
 
 
 
 
Offshore pipeline for increased capacity has according to information from the TSOs not been 

studies as part of the ongoing shared studies or previously. However, offshore solutions are part of 

the electricity connection study carried out in parallel to this study.  

Figure 5-7 First phase of MidCat Girona-Carcassonne – offshore alternative (Source: Ramboll) 

The figure above shows a possible solution with an approximately 120 km offshore section, having 

the same function as the proposed MidCat pipeline and connecting between Enagas and TIGF 

system. However, it would also be possible to have a longer offshore pipeline stretching all the way 

from Spain to the Fos terminal in France, bypassing the TIGF system and connecting to GRTGaz 

system.  

The water depth in Gulf of Lion is less than 100 metres and there should probably not be any 

technical problems which could not be overcome. For comparison the water depth of the Medgaz 

pipeline is more than 2000 metres. Also, a pipeline has been constructed from the Spanish 

mainland to Belearic Islands. Technically an offshore pipeline has the advantage of allowing higher 

operational pressure and hereby higher capacity than traditional onshore pipelines.  

Environmentally, offshore pipelines have been favoured in Norway instead of crossing of 

mountains. Typical environmental problems with offshore pipelines are associated with landfalls, 

flora and fauna, historical heritage as ship wrecks, ammunition. However, in most cases such 

issues have been overcome by detailed planning and surveys.  

Economically, one advantage of offshore pipelines is that only limited land owner compensation is 

requested. Typically, fishermen and others with direct losses are compensated.  

66 

 
 
 
 
 
 
 
 
 
 
5.4

  Full MidCat  

5.4.1

Internal strengthening of Spanish and French system  

The utilisation of the first phase of the MidCat project from Girona-Carcassonne will be restricted by 

the existing pipeline systems, including pipelines, LNG terminals, underground gas storage 

compressor stations and off-take points in Spain and France.  

In the shared study, the bottlenecks have been identified, and based on different scenarios the firm 

capacity has been determined used a conservative approach to ensure firm capacity.  

5.4.2

  Definition of full MidCat and alternative solutions in France 

The following definition of the full MidCat project is used in the shared study.  

Figure 5-8 Full set of phased infrastructures considered by the TSOs in the context of the study (source: 

Joint Technical Study Between ENAGAS, GRTgaz and TIGF) 

This definition is used to achieve a firm capacity of 230 GWh/day (20 mcm/day) from Spain to 

France and 180 GWh/day (16 mcm/day) from France to Spain. Further, it is assumed that the 

French policy of maintaining one zone as expected from 2018 is still enforced.  

67 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
This eastern alternative in France was chosen because GRTgaz proposed to focus on the Eastern 

corridor solution, mainly for the two following reasons: 
• 

This is the solution for which GRTgaz has already achieved several studies and 

obtained ministry approval for Eridan ; 

• 

The Western corridor seems less scalable: at this preliminary stage of analysis, it 

seems more difficult to phase the development as the different infrastructures 

reach saturation almost simultaneously. 

However, a western alternative is also possible as indicated below.  

Figure 5-9 Two main corridors identified in order to achieve integration of MidCat: a) The Eastern 

corridor, flowing through the Rhone Valley to connect the Val-de-Saone artery; b) The Western corridor, 

using the western route to the Arc-de-Dierrey 

The proposed solution for the full MidCat includes differences in dimensions of the different 

sections. The proposed large investments Eridan and Arc Lyonnais are proposed to be DN1200 

pipelines which will have a capacity of more than the double as the proposed capacity of the border 

crossing. It is hence evidently that cost for these lines should be shared by other users in the socio-

economic comparisons. This could be the expansion of the Fos LNG terminal.  

Alternatively it is possible to establish the new pipelines only for some sections as this will increase 

the overall capacity even without a full pipeline. Here, the gas velocity in the existing parallel 

pipelines would set the limit for capacity.  

68 

 
 
 
 
 
 
 
Capacity calculations based on decremental approach 

The analyses in the shared study are based on a decremental approach. It means that the starting 

point is the full MidCat as described above. Hereafter different parts of the full MidCat are omitted to 

see which limitations there will be in the system. 

The target capacity is in all cases 180 GWh/day from North to South and 230 GWh/day from South 

to North.   

Figure 5-10 Procedure for capacity calculation full MidCat (source: Joint Technical Study Between 

ENAGAS, GRTgaz and TIGF) 

Figure 5-11 Elements included France in the different decrement steps (source: Joint Technical Study 

Between ENAGAS, GRTgaz and TIGF) 

69 

 
 
 
 
 
 
 
 
 
 
 
Figure 5-12 Elements included in Spain in the different decrement steps (source: Joint Technical Study 

Between ENAGAS, GRTgaz and TIGF) 

The main limitations of the flow cases are shown in the table below: 

From Spain to France 

From France to Spain  

French side 

Spanish side 

French side  

Spanish side 

Peak demand 

Same 

Certain 

Production from 

Limitations to 

scenario 

infrastructure as 

production in 

UGS and LNG 

Barcelona entry  

LNG and UGS. 

Barcelona 

needed due to 

Local constraints 

Need for outlet 

Local constraints 

bottlenecks from 

capacity as 

Eridan if 

simultaneous 

entry 

Same 

Average winter  

northern entry 

points. 

Certain 

Production from 

Limitations to 

infrastructure as 

production in 

UGS and LNG 

Barcelona entry  

LNG and UGS. 

Barcelona 

needed due to 

Local constraints 

Need for outlet 

bottlenecks from 

capacity as 

Local constraints 

northern entry points 

Bottleneck around 

Lyon 

Eridan if 

simultaneous 

entry. Additional 

bottleneck before 

Paris area. Limits 

Montoir. 

Average summer 

UGS injection 

Local constraints  General constraints 

Limitations to 

creates room for 

gas import from 

Spain Few 

constraints. 

at Northern entry 

Barcelona entry  

points 

Local constraints 

Limitations on 

Lussagnet UGS 

filling 

Table 5-3 Bottlenecks in different scenarios and flow situations 

As for the first step on MidCat, the simulations give certain constraints when less than the full 

MidCat is included.  

70 

 
 
 
 
 
 
 
 
 
 
 
 
The sizing of the different components of the full MidCat means that the full MidCat will contribute to 

other goals than the planned capacity for MidCat. It is obvious that the use of a DN1200 (48”) 

pipeline for Eridan compared to a DN 900 (36”) for the border crossing means that Eridan will not 

only contribute to capacity for MidCat but also for other purposes, such as increase of the overall 

North-South capacity.  According to the shared study the full MidCat infrastructure provides 600 

GWh/day of which only 230 GWh/day will be allocated for MidCat. If there is no need for such 

increase in North-South capacity, there is a mismatch between dimensions of the different 

pipelines.  

In the shared study it has not been analysed if an even larger crossing between Spain and France 

could be included in case of the Full MidCat, which could contribute to bringing down average cost.  

The conclusions on the shared study based on worst case scenarios are that the most severe 

constraints are on the French side. Even with the full MidCat there will be constraints in case of flow 

from North to South, due to the entry point constraints in the North. For gas flow from South to 

North the main constraint is the lack of simultaneous outlet from MidCat, UGS in the South and 

Fos, which could be partly lifted by Eridan and fully with a combination of Eridan and Arc Lyonnais.  

Comments to shared analyses for full MidCat  

The comments given above to the first stage MidCat also apply for the full MidCat.  

Further the additional findings are made concerning the full MidCat analyses:  

-  No optimisation of the first step MidCat and full MidCat with respect to dimensions have 

been made, which means that Eridan and Arc Lyonnais could serve other purposes than 

the interconnector due to the larger dimensions than the first step MidCat.   

- 

The analyses are based on a normal year with respect to weather only. Also, the analyses 

do only cover a few months of the year (summer and coldest winter month). This 

underlines that a very conservative approach has been used.  

-  Possibility of significant increase in gas import from North of France to the French market 

has not been analysed. This could be the case if Nord Stream 2 will provide significant 

new volumes of gas to France instead of LNG import to France and Spain.  

-  Significant increase in gas from Algeria to Spain, such as Medgaz II has not been 

analysed. The influence zone of MidCat in Spain may be too small in such case. 

- 

- 

The flow calculations are only preliminary and it is not clear how the creation of one zone 

in South of France from 2015 has impacted the use of the system.  

The analyses are based on the Eastern corridor; However, it is not clear if a western or 

combined expansion would be more favourable.  

Conclusions on Eridan and Arc Lyonnais 

The shared study shows that the Eridan pipeline and Arc Lyonnais contribute significantly to the 

insurance of capacity from the interconnector between France and Spain. However, the capacity of 

the Eridan and Arc Lyonnais is 600 GWh/day which is more than the double of the target for 

MidCat. Also, the estimated cost of the Eridan and Arc Lyonnais of more than 1 bEUR is more than 

the double of the cost of the first phase of MidCat.  

We do not find that Eridan and Arc Lyonnais should be justified only be increased interconnector 

capacity between Iberian Peninsula and rest of EU. During the open season for MidCat 2010 only 

half of the cost for Eridan was allocated to MidCat.  

71 

 
 
 
 
 
 
 
 
 
 
 
Factors which can influence the need for Eridan and Arc Lyonnais are in addition to flow to/from 

Spain:  

- 

- 

- 

Increase entry of gas from North, e.g. Nord Stream 2 and/or reduced LNG import to Fos  

Lower gas demand in France in general, which will spread the supply from the North to a 

larger part of the country 

Location and use of CCGTs. In the shared study only 50% use was anticipated 

-  Use of underground gas storage as it may be possible to choose between supply to and 

from UGS and the interconnector 

Conclusion on Artere de Midi, Compressor Montpellier 

The choice between a new pipeline parallel to the exiting Artere du Midi or a new compressor 

station is mostly a question about the load factor for the anticipated flow. With large uncertainty it 

can be argued that a compressor station gives more flexibility and lower investment cost. With the 

lack of complete overview over the daily use, this will be the preferred solution.  

As illustrated with the offshore solution for an interconnector between Spain and France, it would 

also be possible to connect such offshore pipeline close to Montpellier and bypass some of the 

bottlenecks in the TIGF area.  

5.4.3

  Firm or interruptible capacity – probability calculations 

The definition of the full MidCat shown above is based on achieving the capacity at the border 

without limitations. A conservative approach is used based on combinations of the following four 

parameters:  
•  Climatic conditions / Domestic demand 
•  Underground storages injection and withdrawal levels 
•  Use of combined cycle Turbines 
• 
LNG terminals production level 

France and Spain have traditionally used a conservative approach for firm capacity with a very high 

probability for guaranteeing the capacity.  

Different countries have different traditions and use of force majeure can impact the firm capacity.  

Security of gas supply is also unclear in some cases. Regulation 994 on security of gas supply on 

Member State level focusses much on capacity of the systems during winter situations and less on 

an overall supply crisis in one or more Member States:  
• 

extreme temperatures during a 7-day peak period occurring with a statistical probability of once 

in 20 years; 

• 

• 

any period of at least 30 days of exceptionally high gas demand, occurring with a statistical 

probability of once in 20 years; and 

for a period of at least 30 days in case of the disruption of the single largest gas infrastructure 

under average winter conditions. 

In a general supply crisis, such as disruption of one of EU´s main suppliers for longer time, it may 

be worth also to focus on long term reduction of supply. Here, interruptible capacity between 

Member States can be used to slowly move gas when there is available capacity.  

Enagas has made probability analyses for the Spanish system for use of MidCat.  

72 

 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 5-13 Probability analyses for the Spanish gas transmission system for use of MidCat 

TIGF and GRTGaz have not carried out similar probability calculations.  

Enagas calculations show that there is a high probability of more than 80 per cent for use of the full 

capacity of the pipeline even without strengthening of the other parts of the network in France and 

Spain. However, this capacity cannot be offered as firm capacity. There is no uniform definition of 

probabilities required to distinguish between firm and interruptible capacity. However, for the 

present interconnector we consider the yearly capacity most important as France, Spain and 

Portugal all have LNG and underground gas storage available to ensure peak load.  

5.5

  Cost and comparison  

Based on the shared study supplemented with own estimates of capacity and using the same 

diameter pipeline for the direct crossing between France and Spain as for the Eridan pipeline, the 

following preliminary estimates are made.  The firm capacity is based on the assumptions 

described for MidCat first phase.  

Dimension Cost 

Firm capacity 
GWh/d

Interruptible capacity
GWh/d

DN900
DN1200
DN900
DN1200

472
627
2075
2230

120
120
230
500

230
500
230
500

Midcat 1st phase
Midcat 1st phase 
Full Midcat incl. Eridan 
Full Midcat incl. Eridan 

Table 5-4 Cost comparison for different capacity and dimensions 

The interruptible capacity will be different with respect to probability for the different cases. 

The cost comparison will be further evaluated in the final report.  

5.6

  Line pack and reduced energy consumption  

Establishing a large diameter pipeline will reduce energy consumption for compressors and will 

further contribute with line pack capacity which will ease balancing. The line pack capacity of a 

DN900 pipeline with 80 bar pressure will be more than 10 mcm.   

5.7

  Connection between France and Germany, Reverse flow and odorisation 

problem  

It has previously been considered to establish reverse flow between France and Germany.  

73 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 5-14 Reverse capacity from France to Germany at Obergailbach (Source: GRTGaz) 

However, it has been considered to be very expensive because of the difference in odorisation 

practises between France and Germany. In France, natural gas is odorised in the transmission 

system, while this is only done in the distribution system in Germany. Therefore, there is a need 

either to change the practise in France or to establish a process plant for removing the odorant, 

which will be expensive in terms of investment and operational cost. No information about the cost 

is available, but it is assessed to be in the order of 500 MEUR including pipelines and deodorisation 

plant.  

TENP and Transitas in Switzerland have recently decided to invest in reverse flow between Italy 

and Germany from 2018 by changing compressor stations in Switzerland and Germany and by 

building Europe´s first deodorisation plant. The impact of this decision may be that gas can flow  

from France to Switzerland and further to Germany and utilise the Transgas deodorisation plant. 

The investment will consequently create more flexibility between all countries in the region.  

Figure 5-15 TENP reverse flow illustration (Source: TENP) 

74 

 
 
 
 
 
 
 
 
Historically the flow direction in the TENP pipeline has been from the Netherlands via Germany and 

Switzerland to Italy. Further a branch from France can also supply gas to Switzerland to Italy. With 

establishing the TAP pipeline from Turkey to Italy there is a possibility to import gas from Azerbaijan 

and in order to make this gas available in Germany, Belgium, France and UK there is a need for 

reverse flow.  

According to GRTGaz, it will be possible to physically import 100 GWh/day of gas from Italy via 

Switzerland from 2018 with the possibility of increasing this level with 100 GWh/day of extra 

capacity. Today, more than 220 GWh/day of gas can already flow from France into Switzerland 

through Oltingue. 

5.8

  Portugal - Spain  – 3rd interconnector 

5.8.1

  Description of 3rd interconnector  

The 3rd gas interconnector between Portugal and Spain consists of three phases according to REN.  
The first phase, which is a precondition for the following two phases consist of a 250 km pipeline 

with a dimension DN700 (28”). The major part, 162 km, of the pipeline will be in Portugal, while the 

remaining part will be in Spain. In addition, there will be meter station at the border.  

The second phase will be the addition of a compressor station in the existing system. The third 

phase will be 67 km in parallel to an existing pipeline in Portugal and according to Enagas also a 

number of additional pipelines in Spain 148 km 30”, 170 km 26” and 307 km 32”.  

Figure 5-16 New interconnector between Portugal and Spain (Source: REN) 

75 

 
 
 
 
 
   
 
 
 
 
 
In addition to provide further connection between the two countries, the new pipeline will also 

provide gas supply to the North Eastern part of Portugal, which is presently not served by natural 

gas.  

5.8.2

  Portugal capacity of interconnectors, LNG and storage 

The capacity of the new pipeline connection will be as follows: 

GWh/day 

From Spain to 

From Portugal to 

LNG import  UGS 

Portugal 

Spain  

50  

97 

141 

80 

30 

25 

First phase  

First plus second 

75 

107 

phase 

All three phases  

141 

VIP Iberico  

Bajoz/Campo Kaior  

Valenca do 

Minho/Tuy 

144 

134 

30 

LNG Sines 

Underground gas 

storage  

223 

80 

Table 5-5 Portugal capacity overview for new and existing supply sources (Source: REN and ENTSO-G) 

The Portuguese system is today consisting of the two pipeline connections to Spain, LNG import 

terminal in Sines and underground gas storage. The main capacity is from the LNG receiving 

terminal, which is hence seen as the determining factor in the N-1 calculations for security of 

supply.  

The overall peak demand in Portugal is expected to be around 400 GWh/day in both scenarios, 

Green and Grey. Under normal situations, the present system will have sufficient capacity. 

However, during a disruption of the LNG terminal in Sines there will be lack of capacity.  

In Portugal, a major part of gas is used for power generation. Some of the CCGTs have been built 

with back up facilities and use of gas oil in emergency situations. This was the case because 

initially there was only one pipeline connection to Spain and no LNG or underground gas storage. 

Due to the use of renewable energy like wind and hydro there are substantial variations in the use 

of gas for power generation in Portugal. This will potentially result in low utilisation of the LNG 

import facility. The increase in pipeline capacity from Portugal to Spain can hence potentially be 

used for increased import of LNG to the Iberian Peninsula and hereby to the rest of Europe if the 

bottleneck between Spain and France is removed.  

Portugal is today very much dependent on import of gas from Algeria via pipeline and from Nigeria 

as LNG. New connections will contribute to less market concentration.  

76 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.8.3

  Portugal drivers behind the 3rd interconnector 

The use of the existing pipelines between Spain and Portugal is shown in the figure below.  

Figure 5-17 Actual use of existing pipelines between Spain and Portugal 

The historical use of the interconnectors shows that there has been an increase in use, reaching a 

high level in 2015.  

Portugal is supplied from Algeria and Nigeria based on long term take-or-pay contracts for almost 6 

bcm/year. These contracts will expire in the period from 2020 to 2026. In this situation there is a risk 

that Portugal will be entirely linked to the global LNG market and consequently have higher prices 

than seen in other countries in Europe. By connecting to Spain at a location closer to the entry point 

from France, it may be possible to link some of the gas supply to the rest of EU.  

A main driver behind the 3rd interconnector is security of supply. Here, the following 9 risks were 
identified in the Portuguese reporting on security of supply regulation:  

1. Infrastructure failure at the Sines LNG terminal 

2. Failure in the Campo Maior link 

3. Failure in the third link with Spain 

4. Failure in the Valença do Minho link 

5. Failure in the infrastructure at the underground storage in Carriço 

6. Failure of the compression station at Carregado 

7. Disruption in the main gas pipeline transporting gas in the RNTGN 

8. Disruption in supplies by third country suppliers 

9. Correlated risks 

In particular the supplies by third country, mainly Algeria and Nigeria were seen as potential long 

term risks.  

Further, the use of gas in Portugal differs from other EU member states as there is less use of gas 

for heating. Instead, gas is used for industries and for power generation as well as for cooking in 

the households. For industries the price of natural gas is the most important compared to other 

countries in EU and elsewhere to maintain the industry competitive.  

77 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
The use of gas for power generation differs wildly from year to year due to the high dependence of 

hydro and wind power in Portugal. In years with less hydro and wind power, there is a need for 

natural gas for back-up fuel in CCGT plants. Out of the 4 CCGT plants in Portugal at least two can 

use gasoil as back up, but no storage is available. Further, the existing coal power plants which are 

old may be decommissioned within the next years.  

The dilemma for Portugal is consequently that the focus of gas use of industries and power result in 

a much more fluctuating gas demand than seen in countries with use of gas for heating.  

5.8.4

 Cost benefit consideration for Portugal-Spain 3rd interconnector 

As long as the bottleneck between Spain and France is not removed, the 3rd interconnector 
between Portugal and Spain will mostly contribute to the following benefits:  

-  Ensure gas at a price level linked to the rest of EU rather than only to the global LNG 

market 

-  Security of supply for Portugal in case of LNG failure  

- 

- 

Increased use of Sines LNG and hereby more competition between different LNG 

receiving terminals 

Increased competition and reduced market concentration in Portugal  

Portugal is in particular vulnerable to the country risk of Algeria. In case of failure of Algerian 

pipeline supply via Morocco, supply of LNG from Algeria may also be reduced.  

In order to fully assess the need for the interconnector it is needed also to assess the electricity grid 

interconnection between Portugal and Spain as a major part of gas is used for power generation in 

Portugal.  

The underground gas storage in Portugal is not used at full capacity. It may be possible to increase 

the use of the facility.  

If the bottleneck between Spain and France is removed, it may be possible to use the Sines LNG 

terminal in a wider European context, which will require increased capacity from Portugal to Spain. 

Further, it may be possible to import gas from France in some cases with high LNG prices.  

In conclusion, the removal of bottleneck between Spain and France is seen as the most urgent and 
should have first priority. The 3rd interconnector between Portugal and Spain will only have full 
value when this has been done.  

78 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.9

  MidCat cost summary including Eridan, Arc Lyonnais, 3rd interconnector to 

Portugal 

The overall investment cost is showed in the table below.  

GRTGaz

TIGF

Enagas

REN

GRTGAz

TIGF
Enagas

REN

MidCat Investments 
Pipelines
Midi
Eridan
Arc Lyonnais
Perche
Barbaira-border
Midi
Figueras-Border
Hostalrich-Figueras
Loop Tivissa Arbos
Loop Villar de Arnedo-Castelnou
Celorico da Beira to Zamora
Celorico da Beira to Zamora
Cantanhede-Mangualde

Diameter

Length
km

1050
1200
1200
900
900
1050
900
900
740
640
700
700
700

200
220
150
63
120
40
25
79
114
214
85
162
67

First step Total cost  Unit cost  First step
km

MEUR

Cost allocated to MidCat

MEUR

48" MidCat
MEUR

120

25
79

470
591
435
125
320
100
29
80
97
160
70
137
58

EUR/m/mm MEUR
2,24
2,24
2,42
2,20
2,96
2,38
1,29
1,13
1,15
1,17
1,18
1,21
1,24

320

29
80

50%
50%
50%
50%
100%
50%
100%
100%
50%
50%
30%
30%
30%

235
296
218
63
320
50
29
80
49
80
21
41
17

470
591
435
125
427
100
39
107
97
160
70
137
58

Total 

Compressors
St-Martin
St-Avrit
Palleau
Barbaira
Martorell
Arbos
Zaragoza
Portugal

Total

Investment total 
OPEX 

Grand total 

1539

224

2672

429

1498

2815

MW

MW

MEUR

MEUR

MEUR

30 New
15 Exp
50 New
7 Exp
36 New
5 Exp
21 Exp
12 New

176

25%

36

60
30
100
15
42
1
5
30

283

2955
739

3694

50%
50%
50%
50%
100%
50%
50%
30%

30
15
50
8
42
1
3
9

157

1654
414

2068

42

42

471
118

589

60
30
100
15
42
1
5
30

283

3098
775

3873

Table 5-6 MidCat and associated pipelines in France, Spain and Portugal (source: Joint Technical Study 

Between ENAGAS, GRTgaz and TIGF and REN with own additions) 

The table includes the cost for the first step of MidCat at less than 500 MEUR. The full MidCat will 

reach a cost of almost 3000 MEUR. With allocation of only half of the MidCat and ArcLyonnais and 

the rest for the North-South integration and to increased import from Switzerland, Germany and 
other sources from the North, and 30 per cent of the 3rd interconnector, the cost will be 1650 
MEUR. Finally, the cost for a full 48” solution for the MidCat including all other pipelines will be 
3100 MEUR. The additional investments for Spanish part of the final stage 3rd interconnector 
between Spain and Portugal has not been included.  

As described above the cost estimates are mostly based on information from the TSOs. It can be 

seen that the unit cost for pipeline, which as a proxy is calculated as cost per metre and mm is also 

the double in France than in Spain and Portugal. This may reflect that no recent design has been 

made as well as difference in terrain and not least right-of-way compensation. It is recommended 

that more updated cost estimates are made based on conceptual design.  

5.10

  Fos LNG extension – Capmax project 

At present there are two LNG terminals in Fos close to Marsailles; the older Fos Tonkin terminal 

and a new Fos Cavaou commissioned in 2010. Both terminals are operated by Engie, who also 

owns the Fos Tonkin terminal. Fos Cavaou is owned by Fosmax, a cooperation between Engie and 

Total.  

The Fos Tonkin terminal is the oldest terminal and is mostly used for import of gas from Algeria as 

the terminal can receive medium size LNG carriers (medmaxup to 75,000 m3 LNG). The Tonkin 

terminal is also used for truck delivery of LNG. The Fos Cavaou terminal can receive large LNG 

carriers (Q-max up to 267,000 m3 LNG) and is as such an attractive terminal not least for receiving 

gas from Qatar and other Middle East sources via the Suez channel as the sailing time will be less 

than for terminals in Northern Europe.  

79 

 
 
 
 
 
 
 
 
 
 
 
Figure 5-18 Fos LNG strategic location (Source: Elengy) 

The present capacity of the Fos Cavaou and Fos Tonkin entry into the French system is 410 

GWh/d equivalent to approximately 13 bcm per year.  

The capacity of Fos Tonkin is 3000 GWh/month or around 3 bcm/year, while the capacity of the 

Fos-Cavaou LNG terminal is 8.25 Gm3 per year in a full year, i.e. around 96.9 TWh per year. 10% 

of the terminal’s capacity is reserved for all shippers, on the basis of short-term contracts, while 

90% of capacities have been subscribed on a long-term basis. 

The CAPMAX projects aim to boost the capacity of the current Fos Cavaou terminal, increasing its 

gas send-out capacity from 8.25 Gm3/year to 16.5 Gm3/year. The increase involves expanding 

LNG storage capacity by building one or two additional storage tanks and doubling regasification 

facilities. 

An open season for the Capmax project was held in 2013, but so far no final investment decision 

has been made. With the present low utilisation of LNG terminals in Europe a final investment 

decision is probably not imminent.  

The cost estimate for the Capmax is according to Elengy around 350 MEUR. However, no details 

are given for this estimate and it will probably depend on the selection of one or two storage tanks.  

The capacity of the Capmax project is almost the same as the technical capacity for the MidCat 

pipeline with a DN 900 mm pipeline (36”) and the cost is in the same order of magnitude.  

The Capmax and the MidCat projects have the same challenges with respect to capacity of the 

North-South connection in Eastern France and possible need for the Eridan project and the Arc de 

Lyonnais pipeline.  

80 

 
 
 
 
 
 
 
 
 
 
 
 
5.11

  Baltic Sea LNG terminals 

An alternative to increasing the interconnector capacity between Iberian Peninsula and France is to 

establish new LNG terminals close to the East European EU member states most exposed to single 

supplier issues. This includes LNG terminals in the Baltic Sea region.  

At present there are two major LNG terminals in the Baltic Sea area; the FSRU in Klaipeda, 

Lithuania which became operational in 2014, and the Polish LNG terminal in Świnoujście which 

received the first LNG cargo late 2015. New terminals are also being planned in Estonia and 

possibly Finland.  

The capacity of the Lithuania LNG is up to 4 bcm, but at present the outlet is restricted to 47 

GWh/day due to pipeline capacity limitations, corresponding to 1.5 bcm. The pipeline system is 

being expanded to supply gas to Latvia and further connect to Estonia from here. The ship size is 

restricted to 160,000 m3 LNG, preventing the terminal to receive the largest LNG ships. 

The Polish LNG terminal has a yearly capacity of up to 5 bcm and can take ships up to 216,000 m3 

LNG. The terminal capacity can be expanded up to 7.5 bcm. Expansion above this size will 

probably require a completely new terminal and additional pipelines to reach the markets, which 

could a.o. include the Baltic Pipe to Denmark.  

New terminals in Finland and Estonia are being planned and can contribute to security of supply 

and diversification of the market. The overall capacity of the East Baltic gas market is limited by 

size of the overall market of only 6 bcm. When the pipeline between Lithuania and Poland is 

established there may be an additional outlet.  

LNG terminals in Germany, Sweden or Denmark are also a possibility. So far only a small LNG 

terminal in Gothenburg, Sweden is progressing. The import capacity of this capacity is limited by 

the pipeline from Denmark to Sweden to less than 1 bcm.  

An LNG terminal in the middle of Denmark could contribute with up to 10 bcm as it could serve 

Sweden, Denmark, Germany and indirectly the Netherlands by redirecting Danish production. The 

plans for such facility are still on pre-feasibility level.  

The shipping time for LNG vessels is found to be approximately 5 days extra for vessels from Qatar 

via the Suez channel than compared to Mediterranean terminals, resulting in a total of 10 days 

extra vessel days per cargo.  

5.12

  KRK LNG terminal in Croatia and terminals in Greece  

The KRK terminal in Croatia is presently in the binding open season phase. The terminal can serve 

the Central and Eastern European market. The terminal is based on onshore tanks and vaporizers. 

The planned capacity is 4-6 bcm/year, tank capacity (full containment): 2x180.000 m³ and size of 

LNG supply ships: 75,000 - 265,000 m³. The KRK terminal can supply gas to Croatia, Hungary and 

possibly to other countries in the region. No information about cost is available.  

81 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
In Greece there are plans for a new terminal in the Northern part of the country as well as 

increasing capacity of the existing terminal close to Athens. Such terminals can in case of 

disruption of Russian supply be used for supplying gas to Bulgaria also. However, with the 

establishment of the TAP pipeline it may also be possible to redirect gas from Azerbaijan towards 

Bulgaria. Romania is almost self-sufficient and will have less use for import of LNG, although 

possibilities for terminals in the Black Sea have been evaluated.  

5.13

  GALSI pipeline 

The Galsi pipeline directly from Algeria to Italy is planned for a capacity of 8 bcm/year. The 

proposed route is via Sardinia and with a possible connection to France by a link to Corsica.  

Figure 5-19 GALSI pipeline (Source: ENTSO-G) 

The pipeline will create access to the two islands, Sardinia and Corsica, and hereby to a new 

market which is presently not served. It will consequently only be a smaller part of the capacity 

which will reach Italy.  

The major impact on the Iberian interconnector is that less gas may be available for Spain via 

pipeline or LNG and there may be more gas supply to France via Switzerland, resulting in additional 

flow from North to South.  

82 

 
 
 
 
 
 
 
 
 
 
 
 
5.14

  Technical Conclusions   

- 

The capacity of the MidCat will depend on how the French, Spanish and Portuguese gas 

systems are used, including pipelines, underground gas storage and LNG terminals. This 

varies day by day and year by year depending on the balance. The available capacity 

analyses do only cover a few snap shots of such situation and is considered very 

conservative. To unlock further capacity of the existing systems it is recommended to carry 

out probabilistic analyses based on historical data also for the French system as it has 

been done for the Spanish. 

- 

The cost estimates for the different pipeline systems are only based on preliminary design 

and routing. There seems to be high estimates for the French components. No 

documentation has been available to support the estimates. It is recommended to carry 

out at least technical feasibility and routing studies, but preferable conceptual or FEED 

design. 

-  A full 48” interconnector between France and Spain should be evaluated by the TSOs in 

addition to the 36” included in their technical study. The capacity could be 20 bcm instead 

of 8 bcm, which would allow for full integration of Iberian Peninsula 

- 

LNG terminals have been identified which from a security of supply point of view can be an 

alternative to the interconnector from Iberian Peninsula. The terminals in the Baltic Sea 

region will have relatively long sailing distance compared to terminals in the Mediterranean 

Sea coast for gas supplied from EU´s main supplier, Qatar. If the terminals are used for 

import they will replace Russian gas, which will then have to move further west and south, 

and hereby create a north to south flow in the Iberian interconnector.  

- 

The Galsi project could contribute to ensure further supply security for gas from Algeria. 

However, hereby it would also create additional need for north to south flow in the Iberian 

interconnector. 

83 

 
 
 
 
6  Cost benefit analyses  

6.1

  Benefits of increased interconnection between Iberian Peninsula and rest of 

EU 

The drivers for benefits of increased interconnections between Iberian Peninsula and the rest of EU 

are summarised in the table below.  

Direction  

Market driven  

Security of supply driven  

South-North 

- Pipeline supply from Algeria increases, 

- Russian disruption of gas supply, or Ukraine 

conventional, shale or TSGP 

or Belarus transit 

- LNG supply via Iberian receiving terminals if 

- Norwegian disruption, in particular Troll field 

other LNG terminals in France and Northern 

or Draupner  

Europe are fully utilised 

- UK-Belgium interconnector failure 

- Price differences between oil indexed prices 

- Nuclear incident in France, closing nuclear 

from Algeria and market based prices in North-

power and increase use of CCGT in France, 

West Europe. In particular the case with low oil 

Germany etc.  

prices  

- Fos LNG terminal disruption  

- Increased LNG supply in case of decline in 

- Disruption of Algerian supply via Tunisia to 

gas production in the Netherlands, Germany, 

Italy for technical or other reasons 

Norway  and Denmark reducing pipeline 

- Groningen field disruption  

- Extreme cold weather in North and East 

Europe and consequently empty storage 

supply to  Europe 

- Improvement in the bargaining position. 

Possibility to engage with a larger variety of 

LNG suppliers, while companies such as 

Sonatrach, NNPC, and Gas Naturel, could 

begin competing with other larger wholesale 

suppliers further up in Europe.  

North-South 

- Ensure full integration of Spain and Portugal 

- Algeria gas supply disruption or Morocco 

into EU market and avoid price differences 

transit 

- Qatar, Algeria or Nigeria LNG Failure  

- Technical fault on Medgaz, or Strait of 

Gibraltar pipelines/compressors 

- Sudden demand increase on Iberian 

peninsula (nuclear disruption, cold/warm 

weather, combination) 

- LNG accident in Spain   

- Increased Russian supply, e.g. Nord Stream 

2 

- High LNG prices globally compared to gas 

market prices on North West Europe 

- Qatar or other LNG suppliers prefer to use 

UK and other LNG terminals outside Iberian 

Peninsula keeping the price high in Spain by 

isolating it from the rest of Europe 

- Contract differences between oil indexed 

prices from Algeria and market based prices in 

North-West Europe. In particular the case with 

high oil prices  

- Take-or-pay obligations for EU suppliers in 

case of demand, warm weather, high gas 

prices 

-  South of the border shippers would have the 

possibility of sourcing gas from the rest of 

Europe as an alternative to Sonatrach, NNPC, 

and other LNG suppliers. 

Table 6-1 Flow drivers normal market situation and security of supply 

84 

 
 
 
Quantification of these benefits are very dependent on the development in gas demand in EU, but 

also in neighbouring countries like Ukraine, Belarus, Morocco, Tunisia, Turkey as well as in the 

producing countries Russia, Algeria and Libya as this will impact the overall need for LNG import to 

EU.  

In particular the EU gas demand uncertainty impacts the benefit, as EU could move from being 

almost completely supplied by pipeline gas to needing more than 100 bcm import as LNG.  

6.2

  North-South or South-North supply assessment and methodology  

6.2.1

  Normal market situation – ENTSO-G green and grey scenarios for demand – revised supply 

from North-West European production  

Historically, the net flow on the France to Spain interconnector has been from France towards 

Spain. However, commercially there is flow in both directions.  

With the forecasts for gas production in North-West Europe (UK, The Netherlands, Germany, 

Denmark, Norway), there will be a tendency to have less supply to Northern Europe and hence to 

shrink the area directly supplied from this direction. This may indicate that the flow direction 

between Spain and France may change or become fluctuating depending on yearly changes. 

However, the overall balance will also depend on new gas infrastructure. This could be pipelines 

like Nord Stream 2 or Trans Saharan Gas Pipeline or new LNG import terminals. TAP project will 

tend to move Algerian gas from Italy to Spain and Portugal via existing infrastructure.  

If no new gas infrastructure is established, the use of LNG terminals will become decisive for the 

flow direction. There seems to be a tendency that Qatar is delivering LNG to terminals in the UK 

and Belgium rather than to terminals on the Iberian Peninsula and France. The reasoning for this 

can be the Qatar ownership of terminals in UK or it can be to isolate the Iberian Peninsula from the 

rest of EU gas market. This factor will have most impact in the low demand scenarios as there will 

be amble LNG receiving terminal capacity.  

Transportation and LNG terminal tariffs will also influence the use of the interconnector. In particular 

the creation of a single zone in France will probably increase the tariffs at the border points.  

6.2.2

  Security of supply  

For security of supply the Iberian Peninsula is very much depending on the situation in Algeria and 

on the global LNG market, in particular Qatar. In such cases, supply by pipeline from the North, e.g. 

gas storage in France will be necessary if the impacts shall be smoothening out. Portugal is in 

particular exposed to country risk for Algeria and Nigeria, the two major suppliers.  

For EU as a whole, the main concern is the disruption of supply from Russia or one of the main 

transit countries, Ukraine or Belarus, or from Norway. The French dependency of Russian gas is 

not clear as a large proportion according to GRTGaz has unknown source. Most LNG import 

terminals are located in the West or South of Europe.  

85 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The use of LNG receiving facilities in UK is restricted by the UK-Belgium interconnector, as the BBL 

pipeline has no capacity from UK to the Netherlands. Even assuming that the most Northern and 

Eastern terminals are used first, there will be a potential for flow from Spain and Portugal to the 

North in case of a Russian disruption.  

Disruption of Trans-Mediterranean gas supply, e.g. due to technical reasons or due to disruption of 

flow in Tunisia will move gas to the North via Spain, assuming that the GALSI project has not yet 

been established.  

A particular case for France is event with nuclear power supply. In such case there will be a need to 

increase supply from all sources, including LNG supply from Spain and Portugal.  

6.2.3

  Quantification of supply cases – methodology  

The different supply cases have been quantified as yearly balances in 2025. Many possible supply 

situations will be possible, mainly depending on the gas policy in gas exporting countries and by 

gas supply companies. The yearly quantifications illustrate possible situations taking into account 

the historical behaviour of gas suppliers and our assessment of the competitive situation.  

The quantification is made for the two demand scenarios, grey – with low demand, and green with 

high demand. However, as recent years have shown, there may be quite abrupt change in gas 

demand in EU in general and in individual countries.  

The supply cases have been made for normal years with respect to weather and climate. In reality 

such year is very seldom and reality will most often differ. This could include warm weather as the 

start of the 2015/2016 winter, high or low hydro power on Iberian Peninsula and rest of EU, 

difference in wind power. Such differences will significantly impact the need for gas and as pipeline 

and storage supply is faster to react than LNG supply it is likely that the initial impact will be on 

pipeline supply, possible followed by a later impact on LNG for filling of gas storage.  

The following infrastructure is assumed to be commissioned before 2025:  
•  Dunkerque LNG terminal 
•  Artere des Flandres, which allows gas from Dunkerque (LNG and Franpipe) to be turned to 

Belgium before odorisation  

TAP pipeline between Greece and Italy with possibility for reverse flow 

•  Arc de Dierrey 
•  Val-de-Saône pipeline  
• 
•  Polish LNG import terminal  
• 
•  Greece to Bulgaria pipeline 
•  Poland to Slovakia, Lithuania and Czech Republic 

TENP reverse flow allowing gas from Italy (TAP) to Germany and France 

86 

 
 
 
 
 
 
 
 
 
 
 
Contrary to this it is assumed that the following projects have not been implemented before 

2025:  

Trans Saharan Gas Pipeline 

•  Medgaz II (the pipeline is prepared with landfalls etc.) 
•  GALSI pipeline between Algeria and Italy  
•  Nord Stream 2 
•  Denmark-Norway and Baltic Pipe 
• 
•  East Ring pipeline from Greece to Slovakia 
• 
•  East Mediterranean pipelines 
•  KRK LNG 
• 

Turk Stream  

Fosmax 

It is assumed that all the EU producers, Norway and Algeria will produce at full capacity in both 

scenarios and that the supply system will be the same in both scenarios. The overall difference in 

EU supply will hence be between LNG import, mainly from Qatar, and pipeline gas from Russia. 

Due to the limitations in the Norwegian gas system to the Continent there will consequently always 

be import via the Franpipe to France.  

It is assumed that the present supply of Russian gas via Ukraine and Belarus will be possible as at 

present. Supply of gas from EU to Ukraine has not been explicitly included in the normal supply 

situations or security of supply situations.  

The purpose of the overall balance is to create a frame around the possible need for increasing the 

interconnector capacity between the Iberian Peninsula and the rest of EU, including need to internal 

investments in the three countries and need for creating possibility for reverse flow with Germany. 

Due to the difference in policy with respect to odorisation, such reverse flow will require 

investments. It is assumed that commercial reserve flow will be possible, which means that the 

following balances are only based on net yearly flow.  

6.3

  Supply cases and balances for France, Spain and Portugal combined – 

yearly balances 2025 – Green and Grey scenarios 

In the following is given a description and possible quantification of gas balance in the three 

countries for respectively the green and the grey scenarios. The balances are made for respectively 

normal market situation and security of supply situations. 

The purpose of the yearly balances is to quantify the possible use of the overall interconnector 

capacity between the Iberian Peninsula and the rest of Europe. The quantifications are based on 

yearly assessments rather than models, as insufficient information about long term contracts and 

commercial behaviour of main players is available.  

6.3.1

  Normal supply situation – Grey and Green scenarios – different prices 

In the Grey scenario the consumption of gas will only grow very modestly compared to the present 

situation in the three countries and the combined EU and Norway production will only decline with 

approximately 20 bcm. The case is hence very similar to the present flow in 2015. 

87 

 
 
 
  
 
 
 
 
 
 
 
 
 
 
France, Spain and Portugal yearly gas balance 

France
Norway - Dunkerque
Belgium
Germany
Switzerland
Spain Pipeline 
LNG Fos
LNG Montoir
LNG Dunkerque
Demand France 
Total France 

Spain
Algeria pipelines 
Pipeline Portugal 
France pipeline 
LNG Barcelona
LNG Bilbao
LNG Mugardos
LNG Huelva
LNG Cartegena
LNG Sagunto
Demand Spain
Total Spain

Portugal
Spain pipeline 
LNG Sines 
Demand Portugal
Total Portugal

2025 bcm/year
Maximum 
Entry

Exit

8

7
5

18
20
19
3
7
12
11
13

103

20

22
3
5
17
7
4
12
12
9

91

5
7

12

5
7

12

3

3

Total 

186

15

EU balance 
Demand EU
EU production 
Norway pipeline
Russia pipeline
Algeria pipeline
TAP pipeline
Libya pipeline
LNG import

LNG France, Spain, Portugal

95
115

10
218

115

Normal market situation GREY
LNG=TTF
LNG=TTF
Qatar to UK

"+5 EUR/MW"+5 EUR/MW"-5 EUR/MWh"

Elastic

Elastic

elastic

Normal market situation GREEEN
LNG=TTF

"+5 EUR/MW"-5 EUR/MWh"-5 EUR/MWh

15
7
10
-5
0
5
4
4
-40
0

15
-4
0
8
3
2
4
4
3
-35
0

4
3
-7
0

-427
95
115
115
25
10
10
57

40

15
20
15
-5
-12
3
2
2
-40
0

15
-4
12
3
2
1
2
2
2
-35
0

4
3
-7
0

-427
95
115
115
25
10
10
57

22

15
7
15
-5
-5
5
4
4
-40
0

10
-4
5
8
3
2
4
4
3
-35
0

4
3
-7
0

-427
95
115
130
20
10
10
47

40

15
17
19
3
-17
1
1
1
-40
0

10
-4
17
3
2
1
2
2
2
-35
0

4
3
-7
0

-427
95
115
145
20
10
10
32

18

5
5
0
-5
1
12
11
11
-40
0

18
-2
-1
8
3
2
3
2
2
-35
0

2
5
-7
0

-427
95
95
95
30
10
10
92

59

15
7
10
-5
0
10
9
9
-55
0

15
-4
0
9
4
3
5
5
4
-41
0

4
4
-8
0

-513
95
115
140
25
20
10
108

62

15
7
15
-5
0
9
7
7
-55
0

10
-4
0
12
5
3
5
5
5
-41
0

4
4
-8
0

-513
95
115
155
20
20
10
98

62

5
5
0
-6
17
12
11
11
-55
0

18
-2
-17
15
5
3
8
7
4
-41
0

2
6
-8
0

-513
95
95
95
30
20
10
168

82

10
10
0
-6
7
12
11
11
-55
0

18
-2
-7
10
5
3
5
5
4
-41
0

2
6
-8
0

-513
95
115
125
30
20
10
118

72

Table 6-2 Yearly supply balance 2025 normal market situation for grey and green scenarios, SW Europe 

and EU (bcm/year) 

For illustration of the flow cases, please see the following maps.  

Figure 6-1 Yearly flow pattern 2025. Grey scenario. LNG=TTF prices  

88 

 
 
 
 
 
 
 
 
 
 
 
 
Figure 6-2 Yearly flow pattern 2025. Grey scenario. LNG=TTF prices, Qatar preference for UK LNG 

import terminals creates need for interconnector 

Three price assumptions are assessed. 1) The base case where LNG price is equal to the North 

West European market price, 2) a higher LNG case where LNG is 5 EUR/MWh more expensive 

than the pipeline gas, and 3) a low LNG case with 5 EUR/MWh less. The variations are less than 

seen in previous years.  

When international LNG prices are low, it is assumed that gas buyers prefer to buy LNG than 

pipeline gas. On the seller’s side the situation will be very different between countries connected to 

EU by pipeline, as Algeria, and countries like Qatar who do not have any direct outlet for gas. We 

assume that Algeria will prefer to sell gas via their pipeline system in a situation with low LNG 

prices to save operational cost for liquefaction.  

In the grey scenario we have further used two variations on the behaviour of the two main gas 

suppliers acting as swing suppliers Russia and Qatar, as it is assumed that Norway will keep an 

almost constant supply. The first variation is with respect to Qatar preference of delivery as this will 

significantly impact the need for gas interconnector. If LNG from Qatar is mainly delivered to UK, 

Belgium, Italy and Poland there will be a net flow from north to south exceeding the present 

capacity of the pipeline. The second variation is in a situation with higher LNG prices, where Russia 

could use this opportunity to supply additional gas and hereby significantly reduce the need for 

LNG. Also in this situation there will be a need for gas supply from France to Spain exceeding the 

present capacity.  

In the Green scenario where gas demand increases, the situation will be different depending on 

delivery location of LNG and how the Russian and Norwegian suppliers will react in situations with 

low LNG prices as there may be south to north flow in such situations. When prices for pipeline and 

LNG gas are the same or LNG prices are highest, there will be little flow in the pipeline. With low 

LNG prices there may be flow from south to north. As there will be capacity of LNG terminals in 

France and Northern Europe it will only be in cases of significant reduction from Russia and Norway 

that the full capacity of a new MidCat will be used. .  

The flow cases illustrate that the need for interconnector will mainly depend on the demand and the 

behaviour of the two main suppliers Qatar and Russia.  

89 

 
 
 
 
 
 
 
 
 
 
6.3.2

  Security of supply – disruption of gas supply from Russia or Norway  

The main scenario is disruption of the Russian supply over a year and a loss of 100 bcm/y from this 

source. Such a long disruption could happen as a consequence of political actions. Shorter 

disruptions could be due to technical faults or problems with transit countries. Further, a situation 

with loss of 50 bcm/y from Norway is considered. This could be because of a technical break down 

of the Troll field or the Draupner platform, which may take years to replace.  

France, Spain and Portugal yearly gas balance 

France
Norway - Dunkerque
Belgium
Germany
Switzerland
Spain Pipeline 
LNG Fos
LNG Montoir
LNG Dunkerque
Demand France 
Total France 

Spain
Algeria pipelines 
Pipeline Portugal 
France pipeline 
LNG Barcelona
LNG Bilbao
LNG Mugardos
LNG Huelva
LNG Cartegena
LNG Sagunto
Demand Spain
Total Spain

Portugal
Spain pipeline 
LNG Sines 
Demand Portugal
Total Portugal

2025 bcm/year
Maximum 
Entry

Exit

8

7
5

18
20
19
3
7
12
11
13

103

20

22
3
5
17
7
4
12
12
9

91

5
7

12

5
7

12

3

3

Total 

186

15

EU balance 
Demand EU
EU production 
Norway pipeline
Russia pipeline
Algeria pipeline
TAP pipeline
Libya pipeline
LNG import

LNG France, Spain, Portugal

95
115

10
218

115

Security of supply situations
Russia -100 bcm
Green
Grey

Norway - 50 bcm
Grey
Green

8
0
0
-7
5
12
11
11
-40
0

0
-1
-5
12
5
3
8
8
5
-35
0

1
6
-7
0

-427
95
115
15
30
10
10
152

81

9
0
0
-7
19
12
11
11
-55
0

0
-1
-19
17
7
4
12
12
9
-41
0

1
7
-8
0

-513
95
115
40
30
20
10
203

102

5
-5
0
0
6
12
11
11
-40
0

10
-1
-6
10
5
2
5
5
5
-35
0

1
6
-7
0

-427
95
65
115
25
10
10
107

72

5
0
0
0
16
12
11
11
-55
0

10
-1
-16
12
7
4
8
8
9
-41
0

1
7
-8
0

-513
95
65
140
25
20
10
158

89

Table 6-3 Yearly flow balances, security of supply with disruption of Russian or Norwegian supplies 

(bcm/year) 

In all cases, this gives a potential for flow from Spain to France which exceeds the present capacity 

considerably in the high demand green scenario. For the grey scenario, it will be sufficient capacity.  

90 

 
 
 
 
 
 
 
 
 
 
In case of disruption of Russian supply it is assumed that the European gas system will be used in 

the following way:  

•  Algerian pipeline gas is sent to Italy instead of to Spain and further into the TAP pipeline to 

supply Greece, Bulgaria and partly Romania. Also the West Balkan countries can be 

supplied in this way by re-directing the Shah Deniz gas away from Italy.  

•  Norwegian gas is sent to Germany and Belgium by fully utilising the supply system to its 

limit and reduce the flow to UK and France if there is not sufficient total capacity 

redirecting some of the gas from Dunkerque to Belgium  

•  Use French LNG import terminals to the limit 
•  Uses Spanish and Portuguese LNG import terminal to also supply France when 

necessary. 

Figure 6-3 Possible flow situation in case of disruption of Russian supply to EU and use of French, 

Spanish and Portuguese LNG terminals 

91 

 
 
 
 
 
 
 
 
 
 
The flow volumes are shown on the figure below: 

Figure 6-4 Security of supply situation. Green scenario. Russian supply reduced by 100 bcm/year.  

A disruption of some of the Norwegian supply will have a number of similar impacts as disruption of 

Russian supply. However, in such case we assume that the Algerian pipeline supply will continue 

as normal and Italy can be supplied by TAP gas as normal. It may be that Norwegian supply to 

France will be completely stopped as priority will be given to Germany and Belgium.  

6.3.3

 Disruption of LNG supply from Qatar, Algerian supply or transit via Tunisia 

For the Iberian Peninsula, in particular Portugal, the main security of supply situation is a disruption 

of supply from Algeria. Further, disruption of LNG supply from Qatar will impact the situation on the 

Iberian Peninsula as in the rest of EU.  

92 

 
 
 
 
 
 
 
 
 
 
 
France, Spain and Portugal yearly gas balance 

2025 bcm/year
Maximum 
Entry

Exit

Algeria - no gas
Grey

Green

LNG default (Qatar - 100bcm)
Green
Grey

Tunisia transit closed
Grey

Green

France
Norway - Dunkerque
Belgium
Germany
Switzerland
Spain Pipeline 
LNG Fos
LNG Montoir
LNG Dunkerque
Demand France 
Total France 

Spain
Algeria pipelines 
Pipeline Portugal 
France pipeline 
LNG Barcelona
LNG Bilbao
LNG Mugardos
LNG Huelva
LNG Cartegena
LNG Sagunto
Demand Spain
Total Spain

Portugal
Spain pipeline 
LNG Sines 
Demand Portugal
Total Portugal

8

7
5

18
20
19
3
7
12
11
13

103

20

22
3
5
17
7
4
12
12
9

91

5
7

12

5
7

12

3

3

Total 

186

15

EU balance 
Demand EU
EU production 
Norway pipeline
Russia pipeline
Algeria pipeline
TAP pipeline
Libya pipeline
LNG import

LNG France, Spain, Portugal

95
115

10
218

115

15
5
10
-7
-5
10
6
6
-40
0

0
0
5
8
5
2
6
6
3
-35
0

0
7
-7
0

-427
95
115
115
0
10
10
82

59

15
5
10
-7
-2
12
11
11
-55
0

0
-1
2
9
7
4
7
7
6
-41
0

1
7
-8
0

-513
95
115
140
0
20
10
133

81

18
15
19
-5
-15
4
2
2
-40
0

10
-5
15
3
2
2
3
3
2
-35
0

5
2
-7
0

-427
95
115
125
25
10
10
47

25

18
20
19
-5
-5
4
2
2
-55
0

10
-5
5
10
3
3
6
6
3
-41
0

5
3
-8
0

-513
95
115
150
25
20
10
98

42

15
7
10
-7
5
2
4
4
-40
0

22
-4
-5
7
5
2
2
3
3
-35
0

4
3
-7
0

-427
95
115
115
22
10
10
60

35

15
7
10
-7
7
5
9
9
-55
0

22
-4
-7
10
5
4
3
4
4
-41
0

4
4
-8
0

-513
95
115
140
22
20
10
111

57

Table 6-4 Possible flow situation in case of disruption of Algerian or LNG supply to EU and use of 

pipeline connections from North  

Disruption of Algerian supply can be compensated by increased LNG supply. It is assumed that 

some Norwegian gas will be sent to Spain in such case. It is also assumed that the Portuguese 

LNG terminal will have highest priority.  

In case of disruption of LNG supply from Qatar, there will be a need to maximise pipeline import. 

However, it is assumed that Algeria in such case will maximise their LNG production which will limit 

pipeline export. In this case it is assumed that pipeline import from Norway and Russia via 

Germany will be maximised. However, due to the UK dependency of LNG this may not be possible.  

Tunisia is the only transit route for Algerian gas to Italy. In case of an interruption, it is likely that the 

gas will be re-routed to Spain via the existing pipelines. Instead, Norwegian gas flow to Germany 

and further to Italy via Switzerland can be maximised and hereby there will be a sharp reduction in 

direct import from Norway and import from Germany.  

6.3.4

 France – increased demand for power sector in case of nuclear reduction  

In case of a decrease of nuclear power production it will be possible to use the existing CCGT 

plants in France as base load. This will give an additional consumption of up to 15 bcm/y. There 

may also be additional gas power production in Spain, but this is not included in the following case.  

93 

 
 
 
 
 
 
 
 
 
 
 
France, Spain and Portugal yearly gas balance 

2025 bcm/year
Maximum 
Entry

Exit

France nuclear + 15 bc
Grey

Green

France
Norway - Dunkerque
Belgium
Germany
Switzerland
Spain Pipeline 
LNG Fos
LNG Montoir
LNG Dunkerque
Demand France 
Total France 

Spain
Algeria pipelines 
Pipeline Portugal 
France pipeline 
LNG Barcelona
LNG Bilbao
LNG Mugardos
LNG Huelva
LNG Cartegena
LNG Sagunto
Demand Spain
Total Spain

Portugal
Spain pipeline 
LNG Sines 
Demand Portugal
Total Portugal

8

7
5

18
20
19
3
7
12
11
13

103

20

22
3
5
17
7
4
12
12
9

91

5
7

12

5
7

12

3

3

Total 

186

15

EU balance 
Demand EU
EU production 
Norway pipeline
Russia pipeline
Algeria pipeline
TAP pipeline
Libya pipeline
LNG import

LNG France, Spain, Portuga

95
115

10
218

115

15
10
10
-7
5
8
7
7
-55
0

15
0
-5
7
4
2
4
4
4
-35
0

0
7
-7
0

-442
95
115
115
25
10
10
72

54

15
13
10
-7
5
12
11
11
-70
0

15
-1
-5
7
6
4
5
5
5
-41
0

1
7
-8
0

-528
95
115
140
25
20
10
123

73

Table 6-5 Possible flow situation in case of increased use of LNG in case of nuclear disruption in France 

In both scenarios the French LNG terminals and existing terminals in EU  will be sufficient together 

with  the existing pipeline between Spain and France.   

6.3.5

 Conclusions on the yearly flow cases  

The yearly flow cases show that the need for increased interconnector capacity in normal market 

situation will mostly be present in the grey scenario with low demand if Qatar continues to supply 

LNG to EU via the UK and Belgium terminals rather than via Iberian terminals.  

94 

 
 
 
 
 
 
 
 
 
If the LNG prices are high there will also be a case if Russia decides to increase supply as such 

gas will almost replace all LNG to EU.  

In the Green – high demand scenario and a situation with low LNG prices there will also be a need 

for additional capacity if Russia and Norway reduce their supply. Such golden age for gas situation 

may become the case if there will be global oversupply of gas.  

The strongest need for increased interconnector between the Iberian Peninsula and the rest of 

Europe will be in the green scenario in the case of a major disruption from the North European 

suppliers, Russia and Norway.  

6.4

  Comparison of interconnector cost with new and expanded LNG terminals 

One of the benefits of increased interconnector between the Iberian Peninsula and the rest of EU is 

that the existing overcapacity of receiving terminals in Spain could be utilised. It can be argued that 

new LNG terminals can be established closer to the end user market in France and rest of EU.  

A simple comparison of cost indicates the possibility for use of Spanish LNG terminals if this was 

the only benefit of an interconnector.  

Figure 6-5 CAPEX per capacity for MidCat and LNG terminals (MEUR/mcm/day)  

The graph shows the economics of scale for pipeline as well as for LNG terminals. The LNG 

extension can only be used in a few cases where there is space for increase of capacity in the port 

facilities and by establishing new storage. It can be considered as the marginal cost for pipelines by 

choosing a larger diameter. Also, in such cases there may be additional cost to bring the gas to the 

market as there may be saturation close to the terminal.  

Similarly for the pipeline there is a huge advantage for choosing a large diameter pipeline if there is 

no need for additional investment at the end of the pipelines. The marginal cost is the difference 

between the DN900 and DN1200 solution assuming that there were other reasons for the initial 

investment.  

95 

 
 
 
 
 
 
 
 
 
 
 
 
 
6.5

  Price differences between Iberian Peninsula and rest of EU 

  Price differences historical  

6.5.1
The interconnector could and should be used to even out potential price differences arising from 
bottlenecks between the countries.  

Spain has for many years been regarded as a high price area due to a combination of dependency 
on LNG, supply on oil indexed contracts from Algeria, and limited possibilities for sourcing of gas 
from the rest of Europe. Below in Figure 6-6  the price developments between the French PEG and 
estimates by Waterborne on the LNG prices in Spain are presented. The graph shows significant 
differences between the areas in some periods during the year, typically during the winter months.  

55

50

45

40

35

30

25

20

15

10

5

H
W
M
/
O
R
U
E

01-01-2010

01-01-2011

01-01-2012

31-12-2012
DATE

31-12-2013

31-12-2014

31-12-2015

Spain LNG

France PEG

Figure 6-6 Historical gas prices, France and Spain (Source: Reuter) 

In a perfectly competitive environment price differences between areas would be adjusted “quickly” 
by arbitrage leaving only the transportation cost as the difference between the areas. From the 
figure below it can be seen that large price differences main arise during winter and are relatively 
long lived.  

Figure 6-7 Gas price difference Spain and France (Source: Reuter) 

96 

 
 
 
 
 
Assuming that the transportation cost amounts to 2.5 euro/MWh, it can be concluded that there are 
no bottlenecks from the south to the north. On the other hand bottlenecks seem to appear at least 
in some periods from France to Spain. Looking at the actual capacity utilization during these 
periods shows that the interconnector has been used to the maximum capacity during these 
periods.  

Thus, there is reason to believe that additional capacity could alleviate potential bottlenecks at the 
border. The welfare gain from this is not easily deducted as future prices can be affected in many 
different ways. However, as an example, the months which are “overpriced” have an average 
consumption of 2.5 bcm assuming uniform distribution of demand over the year (conservative 
assumption as the winter months constitute a larger share of demand). Below the price differences 
corrected for transportation costs are illustrated showing a minimum of 5-6 Euro/MWh and a 
maximum of up to 18 Euro/MWh.  

Figure 6-8 Price difference Spain-France  

Assuming bottlenecks over a period of a month in aggregate and with a price difference of 5 
Euro/MWh gives annual saving of up to 143 MEUR per month.           

6.5.2

  Benefits of interconnector to limit price differences in green and grey scenario 

With the creation of a single market place in France from 2018, the differences in prices between 

the present North and South zone in France will disappear. Instead the price difference will move to 

the border between France and Spain.  

When Spain, Portugal and France all import large volumes of LNG, and when global LNG prices 

are equivalent to the European pipeline prices, there will in a liquid market be a possibility to 

change import locations and hereby avoid large price differences.  

The yearly gas balances indicate that with the selected scenarios, there will during normal years 

only be a need for use of the Iberian LNG facilities to supply the rest of EU in cases with low LNG 

prices compared to pipeline gas and high demand in EU (Green scenario). The volumes will 

depend on the Russian policy and response to competition from lower LNG prices.  

In recent years gas prices on the Iberian Peninsula and South of France have been higher than in 

North Western Europe and there has been a net flow from North to South. This has to a certain 

degree been due to long term contracts and preference of Qatar to deliver LNG to the UK and 

Belgium market rather than to France, Spain or Portugal. The figure below shows the decline in 

LNG supply in general and the preference for supply of LNG to UK.  

97 

 
 
 
 
 
 
 
 
 
 
Figure 6-9   LNG supply to Europe ( source EU Quarterly Report Energy on European Gas Markets 

Market Observatory for Energy DG Energy Volume 8 (issue 3; third quarter of 2015)) 

During recent years the European LNG import has decreased due to declining demand. To create a 

situation where pipeline gas should entirely replace LNG, there will be a need for very high supply 

from Northern Europe compared to demand. This can be because of new supply from Nord Steam 

2 or due to significant decline in demand, e.g. due to years with warm and windy weather (climate 

change) or financial crises. Mandatory use of LNG in countries like Lithuania and Poland as part of 

security of gas supply policy may also redirect Russian gas to Western Europe. In such case, the 

Iberian Peninsula can be isolated and LNG prices can be increased in case of high global LNG 

prices or lack of competition.  

With high LNG prices and high gas pipeline import there will only be between 10 and 15 per cent 

LNG import to EU. To illustrate this, the capacity of the Nord Stream 2 will be larger than the 

present overall LNG import to EU.   

The price difference between LNG and North-West European gas prices may also impact the price 

setting of pipeline gas from Algeria as this gas will only be competing with LNG on the Iberian 

Peninsula, while it is competing with pipeline gas in Italy. It could be assumed that Algerian pipeline 

gas on the Iberian Peninsula can follow the LNG price.  

To illustrate the order of magnitude of the value of price difference, the yearly capacity and a price 

difference of 5 EUR/MWh is used. However, such high price differences may not be sustainable 

over longer periods. For a capacity of 8 bcm the value will be around 500 MEUR per year. With 20 

bcm capacity the yearly savings can be 1200 MEUR. For the situation with equal LNG and TTF 

prices a price difference of 2.5 EUR/MWh is used equal to the tariffs for using the existing system 

from France to Spain.  

Short term arbitrage advantages will occur such as delivery of gas from underground gas storage in 

South of France to Spain in warm years with high storage level.  

The beneficiary of the arbitrage between LNG and pipeline gas will be the consumers, while the 

losers will be gas suppliers and the producers. Further, the owners and users of LNG terminals and 

pipelines will be losers and winners, respectively.  

98 

 
 
 
 
 
 
 
 
 
 
 
 
Spain and Portugal are the most vulnerable to high LNG prices as the lack of competition from 

pipeline gas from the rest of EU makes the country dependent on internal competition between 

LNG exporters to obtain reasonable prices. This situation can only be changed by adding additional 

pipeline capacity.  

6.5.3

  Conclusion on benefit of price differences  

In the Grey scenario it is likely that there will be a continuous flow from France to Spain as Qatar 

prefers to use UK and Belgium LNG terminals. Even when international LNG prices are equal to 

TTF price there will be benefits of increased capacity as the high tariffs for using the existing 

system from France to Spain is assumed to result in a price difference of 2.5 EUR/MWh. The yearly 

benefit is assessed to 200 MEUR.  

With high LNG prices there will be further benefit of additional interconnector capacity up to 500 

MEUR yearly for an additional capacity of 8 bcm/year.  

In years with lower LNG prices than pipeline prices, it is found that there will be less use of the 

interconnector as it will be favourable to use LNG import as close to the end consumers as 

possible. This will result in higher LNG import in France, Belgium, Italy, UK etc., while the Spanish 

and Portuguese terminals will primarily be used for indigenous consumption.  

Assuming that years with high and low LNG price outweigh each other, the average yearly benefit 

will be 200 MEUR for an additional capacity of 8 bcm/year. The NPV of this over 40 years will be 

4000 MEUR.  

In the Green scenario the benefit of additional interconnector will primarily be to use the Iberian 

LNG terminals in situation with low international LNG prices as it is assumed that other terminals in 

Europe will be fully used in such situation. Assuming that this will be the situation for one in five 

years the average yearly benefit will be 100 MEUR.  

6.5.4

  Qatar gas to UK, Belgium creates higher prices in Spain, Portugal 

Qatar and Russia are the two swing producers to the EU gas market at present, and it is expected 

to be the case for years ahead, unless new LNG players as Australia and USA decide to enter the 

market with very large volumes. As Egypt, Yemen and Libya have left the LNG market, there are in 

practice only three players in the European LNG market; Qatar, Algeria and Nigeria. The figure 

below shows the dominance by Qatar with a rising market share which is now more than 60 per 

cent.   

99 

 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 6-10 LNG supply to EU by country (Source: Eurostat) 

By exporting the Qatar LNG to UK and Belgium, it is possible to split the EU gas market into two 

main price areas, the Iberian Peninsula and the rest of EU. This is due to the limited capacity of the 

present gas interconnector between France and Spain. On the Iberian Peninsula there will be no 

competition between Qatar and Russian gas supply to EU as Russia has no access to this market. 

Hereby it will be possible to keep the Iberian gas prices at the global LNG prices or at least at the 

level of rest of EU plus the transportation cost to Spain from France. As a result, UK has now 

overtaken Spain as the largest EU importer of LNG.  

If Qatar instead supplied large volumes of gas to the Spanish LNG terminals and changed the 

pipeline flow from Spain to France, the price would fall to the price in France minus the 

transportation cost from Spain to France. As Qatar partly owns the LNG terminal South Hook in UK, 

there is further incentive to use this terminal rather than Spanish terminals, despite the longer 

sailing distance. 

By exporting LNG to UK and Belgium, Qatar has to compete with Russian gas, assuming that the 

EU producers and Norway produce at full capacity.  

If additional pipeline capacity is established between Iberian Peninsula and the rest of EU there will 

also be such competition between Qatar gas and Russian gas on the Iberian Peninsula.  

6.5.5

  Russian pipeline gas to Iberian Peninsula 

Today, Spain is importing gas via pipeline from Algeria via two pipeline systems of which one via 

Morocco, and from Norway, as part of the Troll field development.  

The existing gas interconnectors between France and Spain are fully booked, or there are 

bottlenecks inside France. There are therefore not any possibilities for export of Russian gas to 

Spain and Portugal via pipeline. The Iberian Peninsula is hereby the only part of EU without access 

to Russian pipeline gas. Increased capacity of the interconnector will open for such import and 

hence a more competitive market.  

100 

 
 
 
 
 
 
 
 
 
 
 
As Russian gas is being replaced by new sources in Lithuania and Poland when LNG import starts 

and in Italy with the start of TAP, Russia will need to find new markets to maintain its market share 

as the traditional markets may also decline. The political change in Ukraine has also resulted in a 

dramatic decrease in gas consumption and import from Russia, allowing for increased export to EU.  

6.5.6

  LNG price increase in Security of Supply situations 

In the following Security of Supply situation, we will use a price elasticity of 10 per cent, implying 

that an increase of European LNG from 70 to 170 bcm/year would result in an increase of 25 per 

cent. This corresponds to using the LNG import prices for Japan instead of Europe in the WEO 

New Policy scenario.  

6.6

  Security of gas supply to rest of EU 

6.6.1

  SoS cases, probabilities and quantification of cost savings from Iberian interconnection 

The benefit of increased capacity of the interconnector for security of gas supply is a combination of 

possibility for increased use of the new capacity, probability and duration of events and the value of 

avoiding disruption of supply in the rest of EU. In many cases it will primarily be countries outside 

Iberian Peninsula and France which will benefit from the increased flexibility, as the existing LNG 

facilities in South Western Europe is already creating security of supply towards e.g. Russian 

supply disruptions.  

In the following the upper value of contribution of security of supply is calculated by assuming that 

the alternative to delivering gas via the interconnector would be to use gas oil in e.g. power plants 

in Germany, France, UK, Portugal etc. Only long term incidents considered as short term incidents 

will typically be covered by use of gas storage facilities. The main driver behind the use of the 

interconnector for security of supply will be to use the idle LNG capacity in Spain, after idle capacity 

has been used in France. One of the uncertainties in such situation is how much the LNG prices 

would increase in such security of supply situations. We have assumed an increase in gas import 

price to Europe of 25 per cent, and using the WEO forecasts this corresponds to LNG prices in 

Japan.  

The security of supply events are described elsewhere in this report. By combining probabilities for 

the events with the use of interconnector and duration of each event of one year, the following 

value can be calculated.  

101 

 
 
 
 
 
 
 
 
 
 
 
 
 
Oil_prices: IEA new policies scenario, flat after 2040

End_year 2060
Start_year 2020

Discount_rate: 0,04

Gasoil price = Crude oil + refinery m
NPV of price difference between gasoil and natrual gas price LNG is 

6,6 EUR/MWh =

12,0 USD/bbl
6,32 bEUR/bcm/year over 40 year
bEUR/year
0,16

Event

Probabaili
ty

Capacity 8 bcm

Capacity 20 bcm

Grey

Green

Grey

Green

Flow 
directio
n
Grey 
and 
Green

NPV (bn Euro) 
Capacity 8 bcm

NPV (bn Euro) Capacity 
20 bcm

Durati
on 
(year)

Grey

Green

Grey

Green

12

North

0,00

0,51

0,00

0,76

Russian disruption of gas supply, or 
Ukraine or Belarus transit

1,00%

Norwegian disruption, in particular Troll 
field or Draupner 

1,00%

UK-Belgium interconnector failure

0,50%

Nuclear incident in France, closing 
nuclear power and increase use of CCGT 
in France, Germany etc. 

0,00%

Disruption of Algerian supply via Tunisia 
to Italy for technical or other reasons

1,00%

Groningen field disruption 

Algeria gas supply disruption or 
Morocco transit

Qatar or Nigeria LNG Failure 

0,50%

1,00%

1,00%

Technical fault on Medgaz, or Strait of 
Gibraltar pipelines/compressors

0,50%

North 
South 

0

0

0

0

0

0

0

8

0

8

8

2

0

0

0

0

0

0

0

0

0

0

0

0

0

10

0

9

2

0

0

0

0

0

0

North

0,00

0,51

0,00

0,57

North

0,00

0,06

0,00

0,06

North

0,00

0,00

0,00

0,00

North

0,00

0,00

0,00

0,00

North

0,00

0,00

0,00

0,00

South

0,00

0,00

0,00

0,00

South

0,51

0,00

0,63

0,00

South

0,00

TOTAL (bn EURO)

0,51

0,00

1,08

0,00

0,63

0,00

1,39

0,00
0,51

1,08
0,00

0,00
0,63

1,39
0,00

1

1

1

1

1

1

1

1

1

1

Table 6-6 Summary of security of supply probability, additional capacity for interconnector, duration 

and economic value NPV 

In the table the value of security of gas supply is calculated based on a unit value taken as the 

difference between price of gas oil and imported LNG multiplied by a probability of the event, the 

need for additional flow in the interconnector and the duration of the event. In this way the focus is 

entirely on events with long duration as short term events will be mitigated by use of underground 

gas storage etc. In the calculations a duration of one year disruption is used as an average. It 

could, however, be as well be ½, 1, 2 or 5 years.  

6.7

  Shorter shipping distance  

The duration of an LNG round trip from Qatar to NW Europe is approximately 7 days than for 

unloading on the Iberian Peninsula or in South of France. With a cost of LNG vessel of 50.000 

USD/day the corresponding extra cost of transportation will be approximately 0.3 EUR/MWh. 

With an additional interconnector capacity of 230 GWh/day, this corresponds to a yearly saving of 

25 MEUR, corresponding to an NPV of 500 MEUR over 40 years.  

6.8

  Algerian short range LNG supplied by pipeline 

LNG liquefaction requires around 5-10 per cent of the gas for compression and cooling. For short 

distance this is much more than pipeline transportation for which a distance of less than 1500 km 

as for transportation from Algeria to Spain and south of France the energy consumption will be 

around 1 per cent. In the following a 5 per cent saving by using pipelines instead of LNG is used.  

The yearly LNG export from Algeria to France was 4.4 bcm in 2014. Assuming that all this volume 

was changed to pipeline transportation, the savings would correspond to around 200 mcm of gas.  

Assuming a gas value equal to a price of 20 EUR/MWh the savings will be around 1.8 EUR/MWh in 

pure energy consumption. The value of the gas will be around 45 MEUR per year, corresponding to 

a NPV of 900 MEUR. However, it can be argued that this benefit will mostly be a benefit for Algeria 

and that the value should be determined as the production cost and not the price. Assuming 

production cost of 6 EUR/MWh, the NPV of benefit will only be 270 MEUR. 

102 

 
 
 
 
 
 
 
 
 
 
 
 
6.9

  Storage uses in South France  

The Iberian Peninsula has only small underground gas storage capacity. With increased capacity 

across the Spanish-French border there will be a possibility for using the gas storage facilities in the 

South of France. This could open for a more flexible use of the LNG import terminals on the Iberian 

Peninsula.  

Due to the high tariffs for crossing the border with the present pipelines, it is not possible to use 

historical data to assess the need for use of storage. It is outside the scope of the present study to 

carry out very detailed storage analyses. 

The benefit of gas storage use has consequently not been quantified in the present analyses.  

6.10

  Increased gas production in Algeria and Trans Saharan Gas Pipeline 

Increased interconnector capacity may contribute to increased gas production in Algeria. As 

described, Algeria has large conventional and unconventional gas reserves. Further, Algeria has 

committed itself to reduce or stop flaring in association with oil production. Easier access to the 

entire EU gas market may contribute to decisions among national and international producers to 

invest in increased production. So far, Algeria has had focus on the Galsi project to bring additional 

volumes of gas to the EU market. With more direct access such major investment will not be 

necessary.  

The benefit for EU of increased gas production from Algeria will be increased competition and less 

need for security of supply if gas can be moved freely around. The benefit for Algeria of increased 

pipeline connection will be saved gas for liquefaction and increased value of production.  

The Trans Saharan Gas Pipeline (TSGP) is a pipeline connection between Nigeria and Europe via 

Niger and Algeria. The pipeline connection could be an alternative to LNG export from Nigeria.  

This is in particular the case because such pipeline may be cheaper than a full LNG chain. 

However, the safety situation in the countries involved also holds back the project. Uncertainty 

about capacity in Spain and between Spain and France is one of the other factors holding back the 

project.  

103 

 
 
 
 
 
 
 
 
 
 
 
 
 
6.11

  Comparison of cost and benefit 

The following table shows the comparison between cost and benefit.  

Benefits 

Price difference 
North to South
South to North

Security of supply 
North to South
South to North

Shorter shipping distance 

Algerian short range LNG supplied by pipeline

Storage use in France 

Algerian gas production or TSGP

Grand Total
Price and security of supply 

Cost (Capex and Opex)
MidCat first step
MidCat incl Eridan etc (50%) and 3rd interconnector to Portugal (30%)
MidCat full - incl all cost 

Table 6-7 Cost-benefit comparison  

Grey scenario
Yearly

Green scenario

NPV 40 yeaYearly

NPV 40 yeaBeneficiary

200

4000

100

Spain, Portugal, France (transit)
2000 France (transit), Germany rest of EU

20

45

?

?

500
0

400

900

5800
4500

589
2068
3694

Spain, Portugal

1080 Germany, Poland, C zech Republic,EU

20

45

?

?

400 Qatar or LNG buyers

900 Algeria or France

France

Algeria, Nigeria

4380
3080

589
2068
3694

It can be seen that the overall cost of the full MidCat weighted with the part of the capacity which 

will be used for the MidCat is around 2 BEUR.  

The total benefits are considerably larger than the cost. However, some of the benefits may be 

overlapping and some of the beneficiaries are outside the EU. Also, it should be highlighted that 

there are considerable uncertainty in the assessments.  

6.12

  Conclusions 

- 

- 

The combination of price advantage and security of supply creates benefits higher than 
cost for the grey as well as the green scenario. However, the contributions differ with 
benefits of north to south flow in the grey scenario and south to north in the  green 
scenario, with a considerable part from security of supply.  
The benefits of the interconnector are uncertain as they will depend on: 

o  Gas demand in EU 
o  Gas supply policy and actions by the two main external suppliers Russia and 

Qatar  

o  Tariff system in France and Spain  

-  Establishing new LNG terminals for security of supply purposes in Northern and Eastern 

Europe will create an increase in the North to South flow from France to Spain as such 
terminals will not only be used for security of supply but also for diversification 

- 

- 

TAP, and potentially Galsi, will with the possibility for reverse flow from Italy to France via 
Switzerland create further north-south flow in France and towards Spain. 

The uncertainty about the actual gas demand in EU (and not only the countries involved) 
results in high uncertainty of the results and how the actual flow would be in case of 
establishing the full MidCat system, including a stronger internal connection in France and 
a new connection between Spain and Portugal could favour a step wise development with 
the first step of MidCat to be built before deciding on the other elements. 

104 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
- 

There is a difference in where the benefit and costs are located in the EU. Some of the 
benefits even fall outside the EU.  

o  Security of supply benefits: Eastern Europe and Germany 
  Spain and Portugal 
o  Price benefits:  

For France the main benefit will be the income created by the transmission system and 

sharing of cost.  

- 

The proposed solution with a DN900 mm for the MidCat crossing of the border and 
DN1200 mm for the Eridan and Arc Lyonnais implies that only a part of the Eridan and Arc 
Lyonnais should be allocated to MidCat project. Alternatively, the first step of MidCat 
should also be established with a DN1200 dimension.  

105 

 
 
 
 
 
 
 
7  References 

The following references have been used for the analyses 

•  Midcat – Joint technical study between Enagas, GRTGaz and TIGF 
•  Probability calculation capacities in MidCat 1st step, Enagas 
•  Analyse coûts/bénéfices des investissements dans les réseaux de transport permettant la mise 

en oeuvre d’un PEG France à l’horizon 2018 Rapport final,14 novembre 2013 

•  Engie, private communication 
•  Enagas, private communication 
•  Elengy, private communication  
•  ENTSO-G Ten year network development Plan 2015, March 2015 
•  ENTSO-G Gas Regional Investment Plan, South Region,  2013 – 2022, xxx 2014 
•  GIE Annual meeting presentation: Network Codes and Market Integration in the South Gas 

Region, April 2015 

Trans Saharan Gas Pipeline, presentation WGC 2015 Paris, Ramboll 

• 
•  Communiqué from EU – Algeria meeting on Energy 5 May 2015 
•  ACER, South gas regional initiative, work plan 2015-2016 
•  Enagas, annual report and development plans 
• 
TIGF, annual report and development plans 
•  REN, annual report and development plans 
•  GRTGaz, annual report and development plans 
•  Sonatrach, annual report and development plans 
• 
•  World LNG Report – IGU 
• 
•  Avaliação dos Riscos que afetam o aprovisionamento de Gás Natural em Portugal 
•  Plano Preventivo de Ação Para o Sistema Nacional de Gás Natural 
•  PROPOSTA DE PDIRGN 2015 PLANO DECENAL INDICATIVO DE DESENVOLVIMENTO E 

3rd Interconnection Portugal –Spain, Project description, REN 

Financial Times, article 23 June 2015 

INVESTIMENTO NA RNTIAT PARA O PERIODO 2016-2025 

•  Network code on Harmonised Transmission Tariff Structures for Gas, ENTSO-G, July 2015 
•  Rethinking entr-exit, EWI, Dr. Harald Hecking, December 2015 

106 

 
 
 
 
 
 
 
 
 
 
P.O. Box 4175 

3006 AD Rotterdam 

The Netherlands 

Watermanweg 44 

3067 GG Rotterdam 

The Netherlands 

T +31 (0)10 453 88 00 

F +31 (0)10 453 07 68 

E netherlands@ecorys.com 

W www.ecorys.nl 

Sound analysis, inspiring ideas 

BELGIUM – BULGARIA – CROATIA - HUNGARY – INDIA – THE NETHERLANDS – POLAND – RUSSIAN FEDERATION – SPAIN – TURKEY – UNITED KINGDOM