COMMISSION STAFF WORKING DOCUMENT Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS on an EU strategy for liquefied natural gas and gas storage
Date: 2016-02-16
Institutions: Directorate-General for Energy, European Commission
Subjects: competitiveness, energy cooperation, energy diversification, energy efficiency, energy storage, energy supply, gas supply, natural gas, storage

EN 

   EN 

   EUROPEAN COMMISSION  Brussels, 16.2.2016  SWD(2016) 23 final   COMMISSION STAFF WORKING DOCUMENT Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS on an EU strategy for liquefied natural gas and gas storage {COM(2016) 49 final}  
 
 
1.  The role of gas in the EU 

Natural  gas  currently  represents  around  a  quarter1  of  gross  inland  EU  energy  consumption. 
About 26 % of that gas is used in the power generation sector (including in combined heat and 
power  plants)  and  23%  in  industry.  Most  of  the  rest  is  used  in  the  residential  and  services 
sectors (mainly for heat in buildings) which has the biggest share in gas consumption.2 

Gas is expected to continue to play a vital role in the EU energy system for decades to come, 
as  the  EU  meets  its  ambitious  targets  on  greenhouse  gas  emissions,  energy  efficiency  and 
renewables and makes the transition to a low-carbon economy. 

In the power generation sector, for example, recent years have seen a decline in the use of gas 
due to factors including low carbon prices, reflecting the surplus of allowances on the market 
following the economic crisis and coal-to-gas price ratios favourable to coal. In recent years 
reforms of the EU's Emissions Trading System (ETS) have been agreed, including the back-
loading of 900 million allowances and the introduction of a Market Stability Reserve that will 
address the current imbalance between  supply and demand for allowances. A higher carbon 
price, together with ongoing and future reforms of electricity and gas markets, as outlined in 
the  Energy  Union  Framework  Strategy,  could  contribute  to  making  gas  more  competitive 
vis-à-vis  other  more  carbon  intensive  fossil  fuels.  Gas  will  have  an  ongoing  role  in  the 
medium term as a complement to renewable power generation and the use of carbon capture 
and storage (CCS) or carbon capture and utilisation (CCU) could see gas remain an important 
part of the power generation mix in the longer term. 

Although  energy  efficiency  policies  are  expected  to  dampen  demand  for  heat  overall,  it  is 
likely that natural gas will remain an important source of heat in industry and buildings over 
the medium term. It will also have a growing role as an alternative transport fuel, for example 
in maritime transport and heavy-duty vehicles (see below). 

The precise level of future EU gas  demand will however  depend on many different factors, 
including  fossil-fuel  prices,  carbon  prices,  future  technology  costs  and  the  choices  made  by 
Member  States  and  energy  companies.  Some  illustrative  projections  based  on  different 
assumptions on these and other factors are shown in the graph below.  

As  can  be  seen,  demand  for  imported  gas  under  such  projections  remains  broadly  stable  or 
increases, as domestic EU production declines. The need for infrastructure capacity can also 
be  expected  to  remain  at  a  high  level,  to  ensure  the  deliverability  of  gas  in  periods  of  peak 
demand. 

1 Source: Eurostat. In 2013, gas represented 23,2 % of the EU's energy mix 
2 Source: Eurostat. Power generation 26,12 %, industry 23,4 % and residential and services 41,5% (2013) 

2 

 
                                                            
2.  International LNG markets 

International  LNG  markets  are  set  for  major  change,  with  substantial  liquefaction  capacity 
coming on stream in Australia and the United States in the period to 2020. Figure [1] is based 
on  projects  that  are  under  construction  or  that  have  been  the  subject  of  final  investment 
decisions and are therefore very likely to become operational. 

The  United  States  and  Australia  are  set  to  become  major  players,  alongside  traditional 
suppliers  such  as  Qatar,  Nigeria,  Algeria  and  Angola,  and  there  is  potential  for  significant 
supply  from  Canada,  Tanzania,  Mozambique,  Iran,  Iraq  and  Libya.  The  Eastern 
Mediterranean  is  also  a  promising  future  source  of  gas  supply  for  the  EU,  with  significant 
resources available in Cyprus, Egypt, Israel and Lebanon.  

Abundant supply is expected to drive further integration of the Atlantic and Pacific basins and 
support the shift towards gas-on-gas pricing,  shorter-term contracts, the use of spot markets 
and  the  rise  of  intermediaries  such  as  portfolio  players  and  traders.  US  projects  can  be 
expected  to  have  a  particular  impact  in  this  regard,  with  many  providing  purchasers  with 
greater  flexibility  (e.g. destination-free  contract  terms).  The  Commission  continues  to 
promote free trade in energy and unconstrained access for EU companies to LNG supplies in 
the  framework  of  negotiations  on  the  Trans-Atlantic  Trade  and  Investment  Partnership  and 
meetings of the EU—US Energy Council. 

The  overall  picture  for  LNG  importers  such  as  the  EU  is  therefore  likely  to  be  positive,  at 
least in the short-to-medium term. LNG prices are expected to be lower than in recent years, 
possibly much lower, and EU imports are therefore likely to increase (as they have since late 
2014).  The exact  level  of  future  imports  will  depend  on competition  with  pipeline supplies, 

3 

 
 
but  a  larger  and  more  liquid  global  market  can  be  expected  to  bring  benefits  in  terms  of 
security and resilience, with more ships on the water at any one time and more supplier and 
consumer countries. 

In  the  medium  term  (from  the  early  2020s  onwards),  as  global  LNG  demand  increases,  the 
market  is  widely  expected  to  tighten  again,  due  to  the  cancellation  or  postponement,  in  the 
face of current low LNG prices, of new LNG liquefaction projects. But  the long-term trend 
remains  one  of  a  move  to  a  larger  and  more  mature  global  commodity  market  with  higher 
levels of liquidity and a growing number of suppliers. 

4 

 
Figure 1:  Current and new global liquefaction capacity (2014-2020)

5 

 
 
3.  Summary of the public consultation 

In  order  better  to  understand  stakeholders’  views  on  the  state  and  functioning  of  the  global 
and  European  LNG  markets,  and  their  expectations  as  to  what  the  EU  could  do,  the 
Commission  held  a  public  consultation  on  the  EU’s  LNG  and  gas  storage  strategy  between 
8 July and 30 September 2015.  

3.1. Statistics 

A high number of responses (137 in total)3 was received, from stakeholders along the entire 
value-chain (see Figure 2), from LNG producers to buyers, terminal and underground storage 
operators, thereby providing a representative sample and a wide range of opinion. The biggest 
proportion came from industry (55 %) and associations (27 %), but public authorities (11 %), 
NGOs (4 %), researchers and citizens (4 %) also made their voices heard. 

Figure 2:  

Responses to the public consultation by stakeholder group 

There were contributions from most Member States (see Figure 3) and from several non-EU 
countries (including the Energy Community, Bosnia Herzegovina, Ukraine, Norway and the 
USA). 

3   All individual submissions are available here:  

https://ec.europa.eu/energy/en/consultations/consultation-eu-strategy-liquefied-natural-gas-and-gas-storage. 

6 

 
 
                                                            
 
Figure 3:  Responses to the public consultation by country of origin 

3.2.  Summary of views 

Stakeholders’ views can be summarised around the following topics: 

Role of gas 

There was a general view among stakeholders, in particular industry and market players, that 
the EU should develop an understanding or vision on the future role of gas. This should be 
coherent  across  policy areas  and  clearly  communicated  to  the  market,  and  is  a  pre-requisite 
for  a  stable  investment  environment.  Some  stakeholders  went  further,  saying  that  the  EU 
should  favour  gas  and  stress  its  vital  role  in  the  future,  thus  sending  a  strong 
security-of-demand signal and making the EU more attractive as a market for gas/LNG. 

Optimal level/share of LNG 

On whether an optimal level or share of LNG in the gas mix exists or can be quantified, an 
overwhelming majority responded that this would be determined by the market (i.e. price) and 
would vary from country to country depending on many factors, including price (LNG vs 
pipeline sources), degrees of diversification and interconnectivity, availability of domestic 
production and storage, etc. The few respondents expressing divergent views suggested that 
the issues should be approached from an infrastructure or regional perspective (e.g. what is 
the minimum required level of LNG-related regional infrastructure? what theoretical 
proportion of LNG could this allow for?) or that LNG capacity should not be less than the 
capacity of a country’s main pipeline or 50 % of its overall pipeline capacity. 

Assumptions (global context and EU regional situation) 

As regards the assessment of the global context and the current situation in the EU’s regions, 
most assumptions were accepted as generally right: 

7 

 
 
(1) The current EU LNG regasification capacity is overall sufficient but there are still 
Member States that do not have access to this source.  

(2) Most regasification capacity is in north-west Europe and the Iberian Peninsula; in recent 
years, relatively low utilization rate has been observed at these terminals; 

(3) There is limited access to LNG in central- and south-east Europe, especially due to lack of 
interconnectivity; 

(4) The floating storage and regasification unit in Lithuania considerably contributed to the 
improvement of the security of supply situation in the Baltic region; 

(5) The international LNG market is expected to show significant growth over the short- to 
medium term. 

The majority of stakeholders responding to this particular question saw the low utilisation of 
LNG terminals as normal given the level of world LNG prices, and characteristic of the LNG 
value-chain, where  global liquefaction capacity is  approximately half that of regasification4. 
Global LNG prices after 2010 (as a consequence of the Fukushima event) pushed Asian LNG 
prices up that attracted cargos away from Europe to the Far East. For Europe (described as a 
market of last resort for LNG), cheaper gas was available through pipelines that could easily 
replace the volumes previously covered by LNG.  

In  that  respect,  it  was  also  stressed  that  low  utilisation  of  a  terminal  did  not  mean  it  was  a 
stranded asset. This in particular is the case for exempted terminals where the investors hold 
long-term  capacity  at  the  terminal  and  thereby  bear  the  cost  of  low  utilization,  or  at  least, 
mitigate the risk of the investment itself. 

Some  respondents  pointed  to  the  lack  of  a  clear  reference  to  the  potential  in  the  eastern 
Mediterranean and questioned some specific assumptions, e.g. that the Iberian Peninsula and 
all  countries  in  central-eastern  Europe  are  vulnerable  in  terms  of  access  to  sufficiently 
diversified sources.   

Infrastructure and the question of stranded assets 

Most respondents agreed that existing infrastructure must be better exploited through effective 
implementation  of  the  Third  Package  and  network  codes,  and  by  better  interconnection 
between Member States and markets, including on the basis of reverse flow capabilities where 
needed. Where new (LNG or other) infrastructure is needed, investments need to be subject to 
a cost/benefit analysis to limit the risk of stranded assets. This applies equally where the main 
driver for investment is security of supply. (See also No ‘one size fits all’ below). 

Barriers 

4 Source: IGU World LNG report 2014, global liquefaction was 301 mtpa, regasification 724 mtpa. 

8 

 
                                                            
(especially 

traders  and  LNG  producers) 

While  in  general  many  stakeholders  (in  particular,  regulatory  authorities  and  terminal 
operators)  argued  that  there  were  no  real  barriers  to  LNG  reaching  the  EU  market,  several 
respondents 
some  potential 
improvements. There is also a marked difference between western and eastern Europe. Most 
functioning LNG terminals  are in  western  Europe, where  markets are considered to be well 
interconnected  and  sufficiently  liquid,  while  central-eastern  and  south-east  Europe  are  still 
of 
lagging 
infrastructure/interconnectivity and market depth and therefore of access to liquid hubs. 
This was also mentioned as an issue in relation to the Iberian Peninsula. 

identified  was 

behind.  Here, 

the  main 

identified 

barrier 

lack 

the 

Potential  improvements  were  identified  in  the  western  markets,  where  exempted  and 
regulated terminals co-exist and are in effect competing, but none were highlighted as needing 
further  EU  intervention,  as  existing  legislation  (with  stronger  enforcement  and  regulatory 
oversight) was considered sufficient to ensure a level playing-field. 

The main issues identified related to transparency, in particular as regards ‘use it or lose it’ 
procedures to prevent abuse of primary capacity-holder status and allow secondary markets 
to function effectively. Respondents also highlighted the wide diversity of such procedures at 
the various terminals, which makes it more difficult for new players to enter the market.   

The gas sector and its needs are changing rapidly, partly due to technological developments, 
and  market  players  –  and  rules  –  need  to  adapt  accordingly.  The  availability  of  more 
innovative/flexible  products  at  terminals  (e.g.  separate  storage  services,  etc.)  and  a 
supportive  regulatory  framework  allowing  for  this  were  highlighted  as  a  potential 
improvement to the current situation. 

In addition, the issue of gas quality was raised by several stakeholders, who pointed out that 
an over-narrow common Wobbe Index5 range would exclude part of the current LNG supply 
and some potential new imports. 

A  few  stakeholders  identified  further  barriers  (more  in  the  context  of  specific  markets) 
relating to: 

  tariff regime in general (too often changing or does not incentivise LNG entry) or as 
regards a failure of transmission tariffs to reflect costs, tariff pancaking6, etc.; 

  more technical issues, such as odorisation or minimum output rates; and  

  access  to  sufficient  or  affordable  storage  capacity,  e.g.  effective  third-party  access 

(TPA), storage obligations or full LNG storage, etc. 

Current legislation 

5 The Wobbe index indicates the interchangeability of a fuel gas; it relates heating characteristics of blended fuel 
gases 
6 When a transportation service is using more than one transmission system and the total amount paid by the user 
for such service is not justified by the services rendered individually by each of the transmission operators 
implied 

9 

 
                                                            
In general, the vast majority of respondents found existing legislation sufficient to overcome 
barriers and called for full, and better, implementation of the Third Energy Package and the 
associated network codes, the Gas Security of Supply (SoS) Regulation7 and the TEN-E8. An 
industry association highlighted the importance in general also of competition rules to ensure 
non-discriminatory access to infrastructure and functioning of the gas market. 

No ‘one size fits all’ 

It was widely accepted that regionally tailored approaches and support may be appropriate in 
specific cases where the interconnectivity and liquidity of markets are still poor and there is 
dependence  on  a  single  supplier.  Most  respondents  felt  that  this  applied  in  general  to  the 
Baltic  region  and  south-east  Europe,  with  some  national  characteristics.  It  was 
recommended that floating storage and regasification unit (FSRU) technology be considered 
for these regions, where additional LNG infrastructure may be needed and where this would 
mainly serve security-of-supply purposes. Special value was attached to regional cooperation 
on matters of infrastructure development, as this would also reduce the risk of stranded assets. 

However,  any  targeted  intervention  should  be  determined  case  by  case  after  careful 
consideration of costs, benefits and market specificities, and be non-discriminatory, minimise 
market distortion and not hamper market development. 

Voluntary demand aggregation 

Most  respondents  cautioned  against  the  idea  of  voluntary  demand  aggregation.  Some 
stakeholders  saw  potential  for  demand  aggregation,  but  strictly  in  crisis  situations.  The  few 
who supported the concept were mainly from the eastern European countries, where markets 
and individual demand volumes are smaller and there is no access to a liquid regional gas hub. 

The main message of those opposing the idea was that such practices should not be politically 
driven  and  agreed  by  governments,  as  they  could  also  lead  to  restrictions  on  competition. 
However,  if  market  participants  saw  the  need,  they  should  be  allowed  to  bundle  demand 
(e.g. to reach sufficient volume for an LNG cargo), subject to trade and competition rules, in 
order to improve their market position and bargaining power vis-à-vis suppliers. 

Technological developments and other uses of LNG; sustainability 

Most  stakeholders  see  an  important  role  for  LNG  in  transport,  as  a  replacement  for  oil,  in 
particular  in  maritime  and  heavy-duty  road  vehicles,  as  a  path  towards  decarbonising  the 
transport  sector.  Tax  regimes  (e.g.  fuel  tax),  available  engine  technology  and  standards 
(especially on gas quality) were mentioned as potential areas for action to eliminate barriers to 
further penetration. Current legislation (several respondents mentioned the Alternative Fuels 
Infrastructure  Directive9  and  TEN-T10)  is  expected  largely  to  address  these  issues.  Some 

7 Regulation (EU) No 994/2010 
8 Regulation (EU) No 347/2013 
9 Directive 2014/94/EU of the European Parliament and of the Council of 22 October 2014 on the deployment of 
alternative fuels infrastructure 

10 

 
                                                            
respondents  from  the  Baltic  states  and  Finland  called  for  their  inclusion  in  the  LNG  Blue 
Corridors programme11. 

Several stakeholders mentioned the potential of exploiting LNG ‘cold’ (cold waste recovery 
at terminals), which could provide further economic and environmental benefits. 

A few respondents referred to a need to address methane leakage through infrastructure and 
technology improvements. 

Storage 

Most  stakeholders  agreed  that  storage  faces  increased  competition  from  other  sources  of 
flexibility. Storage operators should therefore offer a wider range of products that are more 
flexible and responsive to the needs of the market, transparent and competitively priced. This 
may require adjustments in Member States’ legal frameworks. Stakeholders called for a level 
playing-field  for  all  flexibility  products,  including  storage,  and  for  such  new  services  to  be 
allowed to develop. 

Further  major  barriers  concerned  regional  cooperation  and  cross-border  trade.  It  was 
widely  accepted  that  it  makes  sense  to  take  a  regional  approach  to  increasing  the  role  of 
storage in ensuring security of supply. Reference was made to aspects such as infrastructure 
development,  cross-border  access  to  storage  capacity  and  rules  for  using  storage  in  crisis 
situations.  Many  contributors  referred  to  the  Gas  SoS  Regulation,  in  particular  preventive 
action and emergency plans, which should include storage-related measures and agreements 
on their use on a regional scale. 

Respondents expressed partly contrasting views on measures obliging suppliers and traders to 
ensure  that  minimum  volumes  are  stored  at  certain  times  (storage  obligations)  and  to  hold 
strategic stocks. While several stakeholders felt that these were clearly necessary to secure gas 
supply, others underlined their potential for distorting markets and their detrimental effects in 
terms of hampering the enhanced regional use of storage. 

Several stakeholders pointed to transport tariffs for stored gas as a potential barrier, referring 
to  current  discussions,  in  the  context  of  tariff  network  code  development,  on  ensuring  a 
cost-related framework.   

On  questions  regarding  the  market’s  ability  to  ensure  security  of  supply,  that  is  whether 
there  is  a  market  failure,  many  respondents  (in  particular,  suppliers  and  parties  active  on 
developed and liquid markets) highlighted the key role of functioning markets. Most storage 
operators  and  stakeholders  from  central  and  eastern  Europe  stressed,  however,  that  market 
players do not take sufficient account of low-risk/high-impact events and called for proposals 
on tools to ensure preparedness for crisis situations. 

10 Regulation (EU) No 1315/2013 of the European Parliament and of the Council of 11 December 2013 on Union 
guidelines for the development of the trans-European transport network 
11 Funded through the 7th RTD framework programme 

11 

 
                                                                                                                                                                                          
Individual  respondents  proposed  various  tools  to  allow  gas  storage  to  improve  security  of 
supply  and  ensure  that  sufficient  volumes  are  stored.  These  include  market-based  measures 
(auctions, etc.) and non-market measures (e.g. storage obligations and strategic storage). One 
respondent proposed that a ‘toolbox’ be developed, i.e. a set of measures to address specific 
situations  in  the  Member  States,  accompanied  by  a  case-by-case  assessment  on  the  basis  of 
transparent pre-determined criteria. 

Several  stakeholders  recalled  that  required  volumes  of  stored  gas  and  consequently  storage 
capacity  can  depend  on  many  variables,  including  the  degree  of  interconnectivity,  the 
liquidity of the market, the availability of alternative sources of flexibility and the proportion 
of  overall  demand  that  protected  customers  account  for.  National  and  regional  calculations 
should  factor  in  all  these  aspects.  Accordingly,  it  seems  that  required  storage  capacity 
cannot  be  calculated  ex  ante  with  sufficient  reliability  (about  half  of  the  respondents 
expressed this opinion), but should be determined by market forces. 

A  majority  of  stakeholders  preferred  market-based  measures  and  called  for  caution  in 
proposing more interventionist solutions, such as storage obligations (minimum filling levels) 
or  earmarking  volumes  as  strategic  reserves.  As  regards  potential  measures  and  policy 
options,  contributors  generally  accepted  that  ‘no  one  size  fits  all’.  Where  the  market  is  not 
well  developed  or  there  is  a  lack  of  confidence  in  its  ability  to  ensure  security  of  supply, 
tailor-made solutions could be pursued. 

4.  Existing LNG infrastructure in the EU 

Large-scale  regasification  capacity  in  the  EU  in  2015  was  195 bcm/year,  with  23 bcm/year 
under construction; it will reach 213 bcm/year by 2019.12 Planned projects13 could result in an 
additional  146  bcm/year.  Overall,  therefore,  the  EU’s  LNG  import  capacity  is  clearly 
sufficient, taking into account annual gas consumption of 400-500 bcm/year in recent years. 
This  also  means,  however,  that  utilisation  rates  for  terminals  across  Europe  have  been 
relatively  low;  The  average  rate  of  LNG  terminal  utilisation  in  Europe  (of  total  installed 
capacity) has decreased since 2010, from 53% to 25% in 2013, and in 2014 just 19% of the 
total  send  out  capacity  was  used14  (compared  with  a  global  average  of  33 %15).  This  was  a 
result  of  high  LNG  prices  in  Asian  markets  and  competition  with  pipeline  gas.  Also  see 
section 3.2 for more details on the low utilisation rate of EU terminals. 

At the same time, there are Member States in the EU that do not have access to LNG as an 
additional  source  of  diversification  due  to  missing  infrastructure  (interconnections,  reverse 
flow or potentially an LNG import terminal closer to demand). Please see section 8 for more 
details  on  modelling  results  of  the  impact  of  the  current  and  future  gas  infrastructure  on 
potential LNG penetration. 

12 Source: GLE LNG Map & Investment Database 2015. 
13 Non-FID (final investment decision) projects. 
14 Source: GIE 
15 Source: IGU World LNG report 2014; 

12 

 
                                                            
Access regimes 

In  Europe,  regulated  and  exempted  LNG  terminals  co-exist  (see  Table  1);  of  the  22  LNG 
(onshore  or  FSRU)  facilities  in  operation,  15  are  regulated,  six  are  exempted  and  one  has 
hybrid  TPA  arrangements.  With  increasing  interconnectivity,  these  terminals  are  in  effect 
competing  on  the  same  market.  While  regulated  terminals  offer  TPA,  access  at  exempted 
terminals  is  negotiated  directly  between  the  owner  and  the  shippers.  National  regulatory 
authorities  are  responsible  for  monitoring  the  effective  functioning  of  anti-hoarding 
mechanisms and congestion management procedures. 

Case study: Impact on security of supply and competition - the Klaipėda FSRU 

Until  recently,  gas  prices  in  Lithuania  were  among  the  highest  in  the  EU,  in  spite  of  its 
geographical proximity to its historical supplier. The Government commissioned the Klaipėda 
FSRU, which began operations in December 2014. Access to LNG on the global markets now 
acts as a price cap (at levels similar to those on competitive EU gas markets). The terminal 
has  been  instrumental  in  negotiating  a  significant  (around  20 %)  reduction  in  the  gas  prices 
offered by Gazprom. 

13 

 
 
Table 1: 

LNG terminals in the EU16 

Country 

Belgium 
Finland 
Finland 
Finland 
Finland 
France 
France 
France 
France 
Greece 
Italy 
Italy 
Italy 
Lithuania 
Netherlands 
Poland 
Portugal 
Spain 
Spain 
Spain 
Spain 
Spain 
Spain 
Spain 
Spain 
Spain 
Sweden 
Sweden 
United Kingdom 
United Kingdom 
United Kingdom 
United Kingdom 

Name of 
installation 

Zeebrugge LNG Terminal 
Tahkoluoto/Pori LNG Terminal (under construction) 
Rauma LNG terminal (under construction) 
Tornio Manga LNG terminal (under construction) 
Hamina-Kotka LNG terminal (under construction) 
Fos-Tonkin LNG Terminal 
Montoir-de-Bretagne LNG Terminal 
Fos Cavaou LNG Terminal 
Dunkerque LNG Terminal (under construction) 
Revithoussa LNG Terminal 
Panigaglia LNG terminal 
Porto Levante LNG terminal 
FSRU OLT Offshore LNG Toscana 
FSRU Independence 
Gate terminal, Rotterdam 
Swinoujscie LNG Terminal (under construction) 
Sines LNG Terminal 
Barcelona LNG Terminal 
Huelva LNG Terminal 
Cartagena LNG Terminal 
Bilbao LNG terminal 
Sagunto LNG terminal 
Mugardos LNG Terminal 
Gijón (Musel) LNG terminal 
Tenerife (Arico-Granadilla) LNG terminal (under construction) 
Gran Canaria (Arinaga) LNG terminal (under construction) 
Nynäshamn LNG terminal 
Lysekil LNG Terminal 
Isle of Grain LNG terminal 
Teesside LNG port 
Milford Haven — Dragon LNG terminal 
Milford Haven — South Hook LNG terminal 

Type 

large onshore 
small-scale 
small-scale 
small-scale 
small-scale 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large off-shore 
FSRU 
FSRU 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
large onshore 
small-scale 
small-scale 
large onshore 
Gasport for FSRUs 
large onshore 
large onshore 

TPA 
regime 

Nominal annual 
capacity (billion 
m3(N)/year) 

LNG storage 
capacity 
(1000 m3 LNG) 

regulated 
 off-grid 
 off-grid 
 off-grid 
 off-grid 
regulated 
regulated 
regulated 
exempted 
regulated 
regulated 
hybrid 
exempted 
regulated 
exempted 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
regulated 
 off-grid 
 off-grid 
exempted 
exempted 
exempted 
exempted 

9.0 
0.1 

3.4 
10.0 
8.3 
13.0 
5.0 
3.4 
7.6 
3.8 
4.0 
12.0 
5.0 
7.9 
17.1 
11.8 
11.8 
8.8 
8.8 
3.6 
7.0 
1.3 
1.3 
0.5 
0.3 
19.5 
4.2 
7.6 
21.0 

380 
30 
10 
50 
30 
150 
360 
330 
570 
130 
100 
250 
135 
170 
540 
320 
390 
760 
620 
587 
450 
600 
300 
300 
150 
150 
20 
30 
1 000 
0 
320 
775 

16   Source: GIE LNG Map Dataset, May 2015 version. Projects in the planning phase (i.e. for which no final investment decision has been taken) are not included. 

14 

 
  
  
  
                                                            
5.  EU gas storage facilities and storage infrastructure 

Figure 4 

15 

 
 
Available  capacity  in  countries  with  storage  ranges  from  10 %  to  over  100 %  of  average 
winter  demand.  Eight  Member  States  could  meet  50 %  or  more  of  their  peak  demand  by 
drawing on their storage; Austria and Germany could cover all of their peak demand. 

In  central  and  south-east  Europe,  substantial  storage  capacity  is  available  but  unevenly 
distributed across countries. As the only  functioning gas storage facility in the Baltic  states, 
the Inčukalns Underground Gas Storage Facility in Latvia ensures the stability of natural gas 
supply in the region. The geology of the area could theoretically permit a tenfold increase in 
existing storage capacity. In general, greater interconnectivity and regional cooperation could 
result in a better and more efficient use of storage. 

Geological conditions in certain non-EU countries may allow for additional storage capacity, 
from  which  the  EU  could  benefit  if  demand  for  storage  products  made  investments  in  such 
sites and related transmission infrastructure commercially attractive. 

6.  Tools for optimising the role of storage in ensuring security of gas supply 

Member  States  policies'  for  optimising  the  use  of  gas  storage  differ  considerably  and  range 
from a fully market driven approach to non-market based instruments as strategic reserves or 
storage  obligations  at  certain  points  of  time.  The  following  overview  summarises  the 
characteristics  of  direct  government  interventions  in  the  storage  sector  to  earmark  and 
withhold gas for unexpected demand-supply imbalances. 

6.1. Non-market-based instruments 

Overview of existing options with direct relevance for storage 

Principle 

Storage obligation 
Fixed volume of gas secured for winter 
season. 
Determined on the basis of demand 
from protected customers in certain 
weather conditions. 

Governance   Suppliers contract directly with storage 
system operators (SSO). 

Storage use 

Outstanding 
issues 

Storage ‘in the market’ throughout the 
winter period, but in practice use may 
be determined by the need to comply 
with the supply standard. 
Market intervention depends on the 
level of obligation set. 
The SoS risk coverage (peak, volume) 
may depend on the level of obligation 
set by the Member State. 
Use of stored gas does not depend on 

Strategic storage 
Fixed volume of gas stored 
permanently. 
Determined upfront or based on 
specific criteria (import, sales and 
import infrastructure capacity) 
under certain weather conditions. 
Governmental body. 
Suppliers and/or shippers contract 
directly with SSO.  
Storage held ‘out of the market’ 
unless its use is allowed by the 
government. 

Market intervention is usually 
significant, depending on volume. 
High protection comes with high 
costs (‘insurance fee’). 
Release of strategic storage 
volumes dependent on Member 

16 

 
 
 
Member State’s decision. 

Higher import dependency. 

Context of 
application 
Storage obligation (minimum storage requirements) 

State’s decision.  
Clear criteria needed for use to 
avoid interference with 
commercial storage. 
Higher import dependency. 

The effectiveness of a gas system in ensuring security of supply depends on storage capacity 
and  storage  filling  levels.  If  the  storage  facilities  do  not  contain  sufficient  volumes,  an 
unusually  severe  winter  combined  with  technical  problems  could  lead  to  substantial  supply 
shortages that could not be made up for straight away, even if gas imports were increased. 

A  certain  proportion  of  the  stored  gas  stays  in  the  reservoir  (‘cushion  gas’)  to  ensure  a 
minimum  pressure  for  physical  extraction  of  the  gas.  The  ‘working  gas’  is  the  maximum 
remaining volume available for withdrawal. The withdrawal rate in storage facilities with high 
filling levels has proven to be relatively stable, so the impact of low filling levels is usually 
felt at the end of the winter. In particular, it starts to flatten out when a low level (which is 
different for each storage facility, depending on its ‘withdrawal profile’) has been reached. 

In the scenarios that have been examined, the gas supply situation in November appears to be 
largely uncritical. Except in the event of a political conflict resulting in a total  disruption of 
gas supplies, shortages were identified only for the month of February. These were due less to 
increased  demand  in  this  period  than  to  lower  withdrawal  rates,  which  underlines  the 
importance of storage filling levels. 

Storage  obligations  can  be  introduced  instead  of,  or  as  well  as,  strategic  reserves,  which 
permanently  withdraw  certain  volumes  from  the  market.  They  involve  requiring  market 
participants to place and hold a certain volume of gas not permanently in storage but only at 
specific  times  so  as  to  guarantee  that  sufficient  volumes  are  available  for  emergency 
situations, e.g. demand spikes due to cold spells. Unlike strategic reserves, storage obligations 
are effective already ahead of a crisis. 

General 
principle 
Fixing of 
volume to be 
stored 
Duration 

Beneficiary 

Considerations for storage obligations 

Supplier for protected customers and institutions of public interest 
(e.g. police, hospitals) has to put an amount of gas in storage for the winter. 
Percentage of demand for 
Percentage of winter 
coldest period (month), 
demand. 
plus withdrawal capacity. 

Percentage of annual 
demand. 

Heating period (winter). 
Note: if duration exceeds winter period, the measure will be considered as 
strategic storage. 
Protected customers 
only. 

Protected customers and 
public institutions. 

Protected customers, 
public institutions and 
key sectors. 
Specific storage site(s), 
e.g. close to point of 

Location 

Gas to be stored in 
the Member State. 

Gas can be stored outside 
Member State if transport 

17 

 
 
capacity is secured. 

consumption (option 
not used in Europe to 
date). 

Use of stored 
gas 

Cost allocation 

Minimum volumes 
kept in stock for 
winter season. 
Individual costs of supplier. 

Freedom to use gas 
during season. 

Strategic storage 

The  key  element  of  a  strategic  reserve  is  that  a  certain  proportion  of  stored  gas  is  set  aside 
from  general  market  mechanisms,  to  be  used  only  in  specific  scenarios  outside  the  general 
market. The gas in the reserve cannot be traded and may be used only in the event of a supply 
crisis.  

Reserves are considered an appropriate tool to improve security of supply, but organisational 
and practical questions still need to be answered. Apart from determining the volumes to be 
stored,  their  location,  triggers  and  procedures  for  their  release  and  their  impact  on  markets, 
Member States need to entrust an entity with the management of the reserve, or create one for 
that purpose. 

Emergency gas stocks are physical stockpiles of natural gas that are not available to the 
market under normal conditions. Like oil stocks, they can be owned by the government or 
held by the industry on the basis of government-imposed stockholding obligations. They are 
held to protect consumers against non-market risks, i.e. risks that the market cannot cover 
under normal conditions and so fall outside the reliability standards of the gas market. 

Considerations for strategic storage 

General principle 

Fixing of volume to 
be stored 

A fixed volume of gas has to be kept in storage permanently as a 
strategic reserve. 
Obligation not only for winter season (unlike ‘storage obligation’). 
On the basis of gas 
On the basis of the 
On the basis of 
imports to the 
Member State’s 
demand from specific 
Member State 
average demand for a 
customer group. 
(securing supply 
specific period (20 or 
from abroad). 
30 days). 

Duration 
Beneficiary 

Who stores gas? 

Location 

Entire year 
Protected customers 
and public 
institutions. 
Supplier obliged to 
store. 
Gas to be stored in 
the Member State. 

No specific 
beneficiary. 

Storage consortium 
or specific institution. 
Gas can be stored 
outside Member 
State if transport 
capacity is secured. 

Transmission system 
operator (TSO) stores 
Specific storage 
site(s), e.g. close to 
point of 
consumption. 

Use of stored gas 

Authority (government or NRA) defines use in the event of crisis 

18 

 
 
 
 
Cost allocation 

(defined event). 
Individual costs of 
supplier (for 
individual bookings) 
or consortium. 

State-funded (for 
TSO booking). 

19 

 
 
 
 
6.2. Storage-related requirements and policies across Europe 

Source: GSE, CEER and Ascari 

Member States can use a wide range of tools for gas storage, including regulatory intervention 
and  market-based  instruments.  Their  choice  will  depend  inter  alia  on  the  organisation  of 
market,  the  energy  mix  and  the  availability  of  alternative  flexibility  mechanisms  to 
compensate  for  disruptions.  Additional  security-of-supply  instruments  may  be  necessary  to 
prepare for severe large-scale events (e.g. cutting-off of a major supply source, a coordinated 
attack on strategic gas infrastructure, etc.). 

It appears that the market may in general underestimate the security and resilience benefits of 
stored  gas,  since  these  accrue  to  a  broad  range  of  stakeholders  other  than  the  companies 
bearing the costs of storage, i.e. those operating on the storage market. Suppliers, households 
and  the  public  and  private  sectors  all  benefit  in  the  event  of  major  supply  disruption. 
Therefore, some of the benefits of gas storage, notably its insurance value, may be considered 
a public good, which the market may not fully reflect in the value it attaches to its financing. 
Depending on the regulatory framework, strategic reserves and storage obligations in Member 
States may help to internalise the costs and benefits of storage.  

Both strategic storage  and storage  obligations should  be subject to  strict conditions so as  to 
avoid  unnecessary  costs  to  the  gas  system  that  would  reduce  the  overall  competitiveness  of 
gas vis-à-vis other fuels. 

To  ensure  full  transparency  and  cooperation  across  borders  and  allow  Member  States  to 
prepare  appropriate  measures  in  terms  of  impact  on  security  of  supply,  such  non-market 
instruments should be explained in detail in regional risk assessments, preventive action plans 
and emergency plans, as proposed under the revised SoS Regulation. Closure of storage sites 

20 

 
could  be  avoided,  e.g. by  ensuring  a  level  playing-field  between  competing  flexibility 
instruments, inter alia through appropriate transport tariffs. Tariffs should reflect the costs of 
storage facilities and may also take into account the gas security benefits they provide. 

7.  PCIs contributing to the development of the gas market for LNG and gas storage 

A subset of projects of common interest (PCIs), as identified in the second list of 2015 PCIs, 
serves in particular the purpose of the LNG and storage strategy. 

Central East South Europe Gas Connectivity group (CESEC) 

The CESEC group identified six key priority projects that specifically improve LNG access 
for all countries in the region, along two main corridors: 

i. 

ii. 

the LNG regasification facility at Krk, together with the evacuation pipeline towards 
Hungary, would bring a new source of gas to Croatia and its neighbours, from west to 
east; and 

the  Greece-Bulgaria  and  Bulgaria-Serbia  interconnectors,  with  further  reinforcement 
of the Bulgarian system and reverse flow capability for the Romanian network, would 
allow  Greek  LNG  and  Trans-Adriatic  Pipeline  (TAP)  gas  from  the  Caspian  to  reach 
Bulgaria and countries further north.  

These projects will also enable cross-border access to existing storage capacities in the region. 
Additional projects could further improve security of supply in the region, depending on the 
needs of the market and progress with other key projects.17  

Baltic Energy Market Interconnection Plan (BEMIP) group 

The BEMIP group identified nine key priority projects that specifically contribute to LNG and 
storage access in the region. These will connect the Baltic states and Finland to the European 
network (via an interconnector between Finland and Estonia, grid reinforcement between the 
Baltic states and an interconnector between Poland and Lithuania). Once interconnected, the 
enhanced Inčukalns underground gas storage facility will make storage services available to 
the entire regional market. Additional LNG import capacity could be added in the Baltic Sea 
region  countries through new terminals in  Sweden or  Estonia (Paldiski or  Tallinn) or  at the 
existing Świnoujście terminal in Poland. 

South West Europe high-level group 

The  Iberian  Peninsula  already  has  extensive  access  to  LNG,  in  addition  to  supplies  from 
Algeria. However, as mentioned in the Madrid Declaration of March 2015, specific projects 
in  the  region  would  serve  to  eliminate  bottlenecks,  connect  regional  markets  and  maximise 
the diversification of the EU’s gas portfolio. A scalable MidCat project (between Spain and 
France)  and  the  subsequent  development  of  the  3rd  Portugal-Spain  interconnection  would 

17   LNG terminal in northern Greece (to be developed if there is local market demand), offshore Romanian gas 

to the grid and further enhancements of the Romanian system, and a Croatia-Serbia interconnector. 

21 

 
                                                            
make this a reality.18 Other projects seen as enablers of the eastern axis, such as reinforcement 
of France’s domestic gas transmission, have been identified in the second PCI list. 

Other EU projects 

In  addition,  analysis  has  consistently  highlighted  Ireland  as  lacking  diversity  of  supply  and 
Cyprus  and  Malta  as  being  ‘energy  islands’.  The  PCI  process  includes  projects  that  would 
address these vulnerabilities and work is ongoing to determine the most economic solutions 
(which may or may not involve new LNG infrastructure). 

Detailed information on relevant PCIs 

The  table  below  sets  out  basic  information  (technical  characteristics  and  implementation 
timeline)  on  the  projects  referred  to  in  the  strategy.  The  total  cost  of  the  projects  implies 
possible investment needs of around €5 billion, but it should be borne in mind that: 

 

initial  cost  estimates  are  typically  optimistic  and  real  costs  can  easily  be  15-20 % 
above project promoters’ current estimates; and 

  depending on project and design choices (e.g. whether an Estonian LNG project goes 
ahead and, if so, which of the two currently proposed variants will be constructed), the 
total investment figure could also be lower; the same applies to the LNG terminal in 
Krk, where three different developmental stages/options are proposed. 

18   A  ministerial  meeting  of  the  high-level  group  adopted  an  implementation  plan  in  January  2016  and  EU 

co-funding under the Connecting Europe Facility has been allocated to studies for the scalable MidCat. 

22 

 
                                                            
Name of project (PCI 
number) 

How  the  project  contributes  to  Energy 
Union objectives 

Location and type / technology used 

Implementation 
status 
(expected commissioning 
date ) 

Interconnector between 

Estonia and Finland 

[currently known as 

"Balticconnector"]  
(8.1.1) 

The  project  will  end  the  gas  isolation  of  Finland, 
provide access to Klaipeda LNG terminal and, after 
completion  of  GIPL,  further  diversify  gas  sources, 
routes  and  counterparts.  Overall,  it  will  increase 
the  security  of  gas  supply  of  both  Finland  and 
Estonia  by  integrating  markets  in  the  eastern 
Baltic region. 

Location: From Inkoo (west of Helsinki (FI)) to Paldiski (west of Tallinn (EE)) — routing based 
on the TEN-E G122/04 Balticconnector study 

Design and permitting (2020) 

Technology: New 80 km bidirectional offshore pipeline (Inkoo-Paldiski, DN500, 80 bar), plus 
50 km onshore pipeline in EE (Kiili-Paldiski, DN 700, 55 bar) and 20 km onshore pipeline in FI 
(Siuntio-Inkoo,  DN500,  80  bar),  including  metering  and  compressor  stations  at  both  ends 
with nominal capacity of 7.2 mcm/day. Capacity can be increased to 11 mcm/day if network 
capacity in EE and FI is increased. The power of each compressor station is about 10 MW. Of 
offshore  pipeline,  50  km  are  expected  to  be  part  of  the  FI  transmission  system  and  30  km 
part of the EE transmission system.  

EITHER: 

Either project would provide the Baltic states and 
Finland with further diversification.  

Location: New onshore LNG terminal near Paldiski, Harju county (EE), including a reloading 
facility for bunkering and truck-loading bays. 

Design  and  permitting  (2019 
(Stage I)) 

Paldiski 

LNG 

(EE) 

(8.1.2.2) 

OR 

Tallinn 
(8.1.2.3) 

LNG 

(EE) 

Enhancement  of  Latvia-
Lithuania 
interconnection (8.2.1) 

further 

increase 

project  will 

gas 
The 
transportation  capacities  from  the  Klaipeda  (LT) 
LNG  terminal  and  from  other  EU  markets  (once 
GIPL will be commissioned) to Latvia, Estonia and, 
after completion of Balticconnector, Finland. 

Technology: Stage I will have a storage capacity of 160 000 cm LNG with a send-out capacity 
of 3.84 mcm/day; second stage can increase the storage capacity to total of 320 000 cm LNG 
and send-out capacity to 14 mcm/day, subject to market demand.  

Location: Muuga Harbour, near Tallinn (EE) . 

Design  and  permitting  (2017 
(Phase I); 2019 (Phase II)) 

Technology:  New  conventional  onshore  LNG  terminal  near  Tallinn,  at  Muuga  Harbour 
(including  reloading  facilities  for  ships  and  barges,  bio-methane  and/or  methane-rich  gas 
receiving, network injection facility, truck-loading bay), with send-out capacity of 4 bcm/year 
and further potential up to 8 bcm/year. LNG storage  capacity is up to  320 000 cm and the 
ship size on existing berth is 230 m (LOA), with an extension possibility to the second berth 
(also  existing)  with  ship  size  of  350  m  (LOA).  The  terminal  is  capable  of  handling  any  LNG 
tanker that can pass through the Danish Straits 

Location: Riga to lecava (LV) and lecava to the Lithuanian border; Kiemenai station (LT) 

Planned (2021) 

Technology: Construction of new 50 km parallel pipeline from Riga to lecava (LV) and new 43 
km  parallel  pipeline  from  lecava  to  the  Lithuanian  border,  with  capacity  of  12 mcm/day 
(onshore); upgrade of a gas metering station in Kiemenai (LT). 

23 

 
 
Name of project (PCI 
number) 

How  the  project  contributes  to  Energy 
Union objectives 

Location and type / technology used 

Enhancement 
Estonia-Latvia 
interconnection (8.2.2) 

of 

The project will enable gas to flow from north to 
south, i.e. from Finland and Estonia to Latvia and 
Lithuania. 

Location: Viljandimaa, Karksi, Puiatu (EE) 

Technology: Upgrade of an onshore pipeline to a capacity of 10 mcm/day. The power of the 
compressor station(s) is 35 MW. 

Implementation 
status 
(expected commissioning 
date ) 

Design and permitting (2019) 

Poland-Lithuania 
interconnection 
(8.5) 

[GIPL] 

states 

The  project  is  a  game-changer  in  the  eastern 
Baltic  region.  It  will  end  the  gas  isolation  of  the 
Baltic 
of 
Balticconnector, also of Finland. It will provide the 
region  with  access  to  diversified  sources  of  gas 
(including LNG) from central Europe. 

completion 

after 

and, 

Location: Rembelszczyzna (PL) — Jauniunai (LT) 

Design and permitting (2019) 

Technology: New onshore, bi-directional pipeline with a total length of 534 km (177 km in LT 
and  357  km  in  PL)  and  capacity  of  2.4  bcm/year  in  the  direction  PL->LT  and  up  to  1.7 
bcm/year in the direction LT->PL. 

The capacity in the direction PL->LT may be extended up to 4.1 bcm/year in the second stage 
of project development.  

Enhancement 
of 
Inčukalns  Underground 
Gas Storage (8.2.4) 

Inčukalns (LV) is the only UGS in the eastern Baltic 
region  that  (once  the  necessary  transmission 
capacity  is  provided)  could  provide  services  to 
Poland, Lithuania, Latvia, Estonia and Finland. 

Location: Vidzeme, 45 km from Riga (LV) 

FID (Stage 1) 

Technology: Upgrade and extension of an aquifer storage facility with the following technical 
characteristics: 

(Stage  1  &  2: 2022;  Stage 
3: 2027) 

- current working gas volume: 2 300 mcm; after extension 2 635-2 835 mcm; 

- current withdrawal capacity: up to 28-30 mcm/day; after modernisation (expected): 34-35 
mcm/day; 

- current injection capacity: 17 mcm/day; after modernisation: 21-22 mcm/day; 

- cycling rate: 1 time/year (seasonal storage).  

Interconnector  Greece-
Bulgaria  [IGB]  between 
Komotini  (EL)  -  Stara 
Zagora (BG) (6.8.1.) 

Key  route  (together  with  the  interconnection 
point  Sidirokastro-Kulata)  to  carry  gas,  e.g.  from 
TAP and Greek LNG, to Bulgaria and further north. 

Location: Between Komotini (EL) and Stara Zagora (BG). 

Permitting (2018) 

Technology: New 185 km onshore pipeline with a capacity of approximately 13.7 mcm/day. 
The power of the compressor station(s) is approximately 20 MW. 

24 

 
Name of project (PCI 
number) 

How  the  project  contributes  to  Energy 
Union objectives 

Location and type / technology used 

PCI  Gas  interconnection 
Serbia 
Bulgaria  — 
[currently 
known  as 
"IBS"] (6.10.) 

Necessary 
rehabilitation, 
modernisation and 
expansion of the 
Bulgarian transmission 
system (6.8.2) 

Crucial  diversification  and  security  of  supply  link 
for Serbia.  

Location:  Sofia  district,  from  Sofia  to  Kalotina  (BG),  and  then  through  Dimitrovgrad  to  Nis 
(RS) 

Specific system reinforcement to ensure that gas 
can flow in and out of Bulgaria across its existing 
and planned interconnectors with Greece, Serbia 
and Romania. 

Technology: New 150 km onshore pipeline with a capacity of 1.8 bcm/year connecting the 
Bulgarian and Serbian gas systems. 

Location: Existing gas transmission infrastructure in Bulgaria 

Technology: Activities relating to the overall rehabilitation, modernisation, reinforcement 
and expansion of the existing gas transmission infrastructure in Bulgaria (modernisation and 
rehabilitation of compressor stations, inspections, repair and replacement of sections; 
expansion and modernisation of the existing network). 

Implementation 
status 
(expected commissioning 
date ) 

Feasibility studies(2018) 

Design of the BG section 

Feasibility studies/Front End 
Engineering Design 
(FEED)/permitting (2020) 

Romanian 
reinforcement 
Bulgaria-

Phased 
system 
the 
(on 
Romania-Hungary-
Austria corridor (6.24.2) 

bidirectional 

System reinforcements to ensure that existing and 
planned 
interconnectors  with 
Bulgaria  and  Hungary  are  integrated  into  the 
regional  market.  The  project  will  allow  cross-
border capacity to reach 1.5 bcm/year to Bulgaria 
and 1.75 bcm to Hungary. 

Location: Podișor-Corbu-Hurezani-Hațeg-Recaș-Horia Pipeline 

Design (FEED) (2019) 

Technology:  New  478  km  onshore  bidirectional  pipeline  on  the  Podișor-Corbu-Hurezani-
Hațeg-Recaș  route,  with  a  transmission  capacity  towards  Bulgaria  of  1.5  bcm/year  and 
towards Hungary of 1.75 bcm/year. Compressor stations in Podișor, Bibesti and Jupa are also 
included. 

Phased  development  of 
an  LNG  terminal  in  Krk 
(HR) (6.5.1) 

LNG  market 

The  worldwide 
can  provide 
opportunities  for  diversification  and  security  of 
supply to Croatia and the broader CESEC region. 

Location: Omišalj, on the island of Krk (HR) 

Technology: LNG terminal based on a migration concept: 

Feasibility/FEED/permitting 
(2019) 

1st  phase:  LNG  Regasification  Vessel  —  installation  of  receipt  of  LNGRV,  with  the 
corresponding annual send-out capacity of 1-2 bcm/year; 

2nd phase: Floating Storage Unit — storing LNG on a vessel; 

— onshore regasification — a segment of the future LNG terminal, with corresponding send-
out capacity of 2-3 bcm/year; 

3rd phase: LNG terminal onshore, with corresponding send-out capacity of 4-6 bcm/year. 

25 

 
Name of project (PCI 
number) 

How  the  project  contributes  to  Energy 
Union objectives 

Location and type / technology used 

Zlobin  —  Bosiljevo  — 
Sisak  —  Kozarac  — 
Slobodnica (HR) (6.5.2) 

Gas from the LNG terminal in Croatia needs to be 
brought to market, including beyond Croatia. 

Location: Zlobin via Bosiljevo, Sisak, the Kozarac gas node to Slobodnica (CZ) 

Technology:  Construction  of  new,  upgrade  and  extension  of  existing  pipelines  with  a  total 
length of 308 km, as follows: 

Implementation 
status 
(expected commissioning 
date ) 

Feasibility/FEED/permitting 
(2019) 

- Zlobin — Bosiljevo pipeline (58 km); 

- Bosiljevo — Sisak pipeline (100 km); 

- Sisak — Kozarac pipeline (22 km); 

- Kozarac — Slobodnica pipeline (128 km). 

The capacity is 30 mcm/day 

26 

 
8.  LNG penetration and impact of selected PCIs 

The analysis considers four scenarios to assess the potential penetration19 of LNG in the EU. 
In order to be able to measure this, a theoretical approach was taken based on an assumption 
that LNG and domestic production are the only available supply sources to cover total 
demand on an average winter day. The total demand is the sum of daily final gas demand (i.e., 
from households, commercial activities and industry) and demand for electricity generation20. 
Storage and pipeline imports are not considered. Prices and other types of technical or 
economic barrier are disregarded. 

The scenarios are as follows: 

1.  LNG is used to cover only the national final gas demand of the Member State with an 

operating terminal (Figure 5);  

2.  A cooperative approach is taken, whereby Member States with LNG capacity exceeding 

national gas demand share the surplus with neighbouring countries with sufficient 
interconnection capacity (Figure 6); 

3.  New up-coming LNG terminals and a set of relevant PCIs identified by the current 

strategy (Figure 7) are taken into account with LNG supply still being used locally; and 

4.  A cooperative approach is taken, using the new infrastructures referred to in the third 

scenario (Figure 8). 

Member States cooperate by covering only a proportion of their national demand themselves 
and leaving the surplus supply available for neighbouring countries. The proportion is 
calculated by dividing the total available21 extra LNG capacity in a given region (i.e. a group 
of Member States linked by cross-border points) by regional aggregated gas demand, once 
domestic production is discounted. The transfer of LNG supply among Member States is 
constrained by aggregate capacity at cross-border points. The intensity of LNG use is 
quantified using the 'LNG supply index', calculated as the percentage of national gas demand 
covered by available LNG capacity. Maximum daily LNG capacity and the capacities at 
cross-border interconnection points on the primary market are set using 2014 data published 
by ENTSOG22 and Gas LNG Europe23. Final gas demand is determined under average winter 
conditions and Scenario A in ENTSOG's Ten-year Network Development Plan 2015.24 
Demand for electricity generation is derived from 'peak demand for power generation' (Vision 

19 i.e., the proportion of total supply that LNG could account for on an average winter day. 
20 The definitions used in the ENTSOG Ten-Year Network Development Plan are applied here. 
21 Available capacity is not total national surplus capacity, but the part of it that could be potentially sent to a 
neighboring Member State through the interconnection points. 
22 http://www.entsog.eu/maps/transmission-capacity-map  
23 http://www.gie.eu/index.php/maps-data/lng-map. For Greece, the value declared in the national Risk 
Assessment is applied. 
24 http://www.entsog.eu/publications/tyndp#ENTSOG-TEN-YEAR-NETWORK-DEVELOPMENT-PLAN-
2015.  

27 

 
                                                            
3 scenario) and rescaled for the average winter25. National production is based on the 
ENTSOG plan. 

8.1. Scenario 1 

Figure 5   Current potential penetration of LNG in Member States with an operating terminal (assuming no cooperation 
between Member States) 

25 It has been assumed that the ratio between electricity demand and final gas demand for the peak condition is 
the same as for the average winter condition. This assumption could bias upward the demand for electricity in 
some Member States. JRC derived average winter consumption for electricity generation for Bulgaria from the 
Bulgarian Risk Assessment. 

28 

 
 
                                                            
Current LNG penetration at national level shows that not all Member States with at least one 
LNG terminal could cover their national gas demand and have extra capacity to export 
(Figure 5).26 France, Italy, Greece and Belgium do not have excess export capacity. Their 
available LNG capacity can partly cover national gas demand. The overall extra capacity of 
LNG in this scenario is substantial but not shared: 3.4 mcm in the Baltic region and 95.3 mcm 
in the rest of Europe for an average winter day.   

Note: If a Member State has extra LNG capacity to export to other Member States, it is 
marked in blue to stress its role of potential exporter. Even in these cases, the LNG supply 
index may be lower than 100 %, as LNG may cover only part of its demand (the rest being 
covered by domestic production). This is the case with the UK, for example: when the LNG 
capacity is shared with other Member States, the surplus LNG is exported, while all domestic 
production is consumed locally. The LNG supply index therefore decreases as the exported 
amount is deducted.  

8.2. Scenario 2 

26 The Netherlands is modelled in each scenario considering only the high calorific gas system. 

29 

 
                                                            
Figure 6 Potential LNG penetration under a cooperative approach with 39 % of demand for the Baltic Region and 15 % for 
the rest of Europe (excluding Bulgaria and Greece, which form an isolated region) 

All Member States except Bulgaria and Finland27 could benefit from cooperation, by using 
the extra available LNG capacity (Figure 6). The average national increase in the LNG supply 
index for Member States in need is 12 %, taking into account the constraints imposed by 
cross-border interconnection capacities. The intensity of cooperation is 39 % for the Baltic 
region and 15 % for the rest of Europe (excluding Bulgaria and Greece, which form an 
isolated region with no extra LNG available). The main export flows are from the UK and the 
Netherlands to central and south Europe, and from Spain to France. Lithuania can cooperate 

27 Finland has one small scale LNG liquefaction terminal, and 2 small-scale off-grid regasification terminals 
under construction 

30 

 
 
                                                            
only with Latvia and Estonia, as the Baltic region is still isolated from the main grid. Greece 
cannot share with Bulgaria, and south-east Europe is in need of supply. The potential of the 
Iberian Peninsula is still underexploited because of the limited interconnection capacity with 
France and the absence of reverse-flow capacity from France to Germany and Belgium. 

8.3. Scenario 3 

If we factor in new upcoming LNG terminals and some relevant PCIs, the EU's LNG potential 
improves further (Figure 7). Overall extra capacity increases to 139 mcm for an average 
winter day. All Member States are connected to a single EU gas network. Estonia and Croatia 
become potential exporters. Poland is able to cover a third of its national demand. France 
increases its utilization. Cross-border capacities are increased in the South-East Corridor and 
in the Iberian Peninsula. The Baltic region is linked to the main EU grid and Croatia supplies 
central-eastern Europe.  

31 

 
Figure 7   Potential penetration of LNG after completion of relevant PCIs (including new LNG terminals and 
interconnections), without cooperation between countries 

8.4. Scenario 4 

All Member States could benefit even more by cooperating and using the extra available LNG 
capacity (Figure 8). The average increase in the LNG supply index in Member States without 
LNG terminals is 19 %, taking into account the constraints imposed by cross-border 
interconnection capacities. The intensity of cooperation is 22% for all Member States in need, 
increasing the volume of LNG shared. There are new export flows from Estonia to the Baltic 
region, from Lithuania to Poland and from Croatia to Hungary and south-east Europe. In this 
scenario, Italy cannot completely cover its cooperative share of gas demand, falling 3 % short 

32 

 
 
 
of its expected LNG supply index value.28 Residual surplus supply coming from Spain to 
France is trapped due to the absence of reverse flow to Germany or Belgium and the capacity 
of the cross-border interconnection with Switzerland now acting as a bottleneck. Other extra 
LNG supply is available in the Baltic region because of the limited capacity of the new 
Poland – Lithuania interconnection, from Lithuania to Poland. 

Figure 8   Potential penetration of LNG after completion of relevant PCIs and with cooperation between countries; 35% of 
demand is covered for Member States in need 

28 In other variants of this scenario, Slovakia and/or Greece are unable to achieve their targets if Italy does so. 
Slovakia can never fully achieve its target because of the limited capacity of the interconnection with Hungary. 
There are possible solutions whereby all the three fall a little short of their targets. We have taken this scenario to 
highlight the positive impact of the PCIs in the North-South Gas Corridor. 

33 

 
 
                                                            
9.  LNG as an alternative fuel in transport, heat and power 

The use of LNG as an alternative fuel to diesel in heavy duty road transport such as lorries 
can  contribute  significantly  to  the  reduction  of  pollutant  emissions  such  as  NOx,  SOx  and 
particulate  matter  (PM),  and  to  noise.  An  extensive  demonstration  of  the  technology's 
feasibility is being carried out under the LNG Blue Corridors project29. 

The  current  LNG  vehicle  offer  in  the  EU  remains  limited,  due  the  lack  of  EURO  VI 
compatible30  high  power  lorries,  but  is  expanding.  Some  vehicle  manufacturers  are  already 
offering  EURO  VI  lorries.  Others  have  announced  that  they  will  start  marketing  them  this 
year or next. 

Demand for LNG from EU road transport fleet operators is increasing. The development of 
the  necessary  infrastructure  is  under  way  with  significant  support  from  the  TEN-T  CEF 
Programme.  

The  use  of  LNG  in  maritime  transport  permits  the  sector  to  meet  the  requirements  for 
reducing  the  sulphur  and  nitrogen  content  in  marine  fuels  in  the  Emission  Control  Areas. 
Figures for reductions in specific emissions are as follows31:  

  NOx   up to 90% 
  SOx   up to 95% 
  PM32   nearly 100%,  

LNG  use  in  shipping  can  also  cut  CO2  emissions  by  up  to  25%,  and  the  use  of  LNG  can 
therefore  support  the  European  Commission's  ambition  to  cut  emissions  from  the  shipping 
sector by at least 40% from 2005 levels by 2050, and if feasible by 50%33.  

Essential to this are the technical works necessary to facilitate the use of LNG in a safe and 
interoperable  way,  which  will  be  completed  in  international  fora  and  within  the  EU  to  the 
timeframe  set  out  in  Directive  2014/94/EU  on  the  deployment  of  alternative  fuels 
infrastructure. 

The work of the European Sustainable Shipping Forum, which was set up in 2013 by the 
European Commission and which harnesses the expertise of government and industry experts,  
will be crucial in this regard, in particular in the context of the development of international 
LNG bunkering standards covering safety, training, gas quality aspects, ship-supplier 
commercial relations, procedural/operational aspects, certification, standardisation and all 
other remaining legislative and operational gaps identified by the EC Study on the completion 
of an EU framework on LNG-fuelled ships and its relevant fuel provision infrastructure34. 

29 http://lngbc.eu/ 
30 http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32007R0715 
31 https://lngforshipping.eu/about-lng/environment-sustainability 
32 Particulate Matter 
33 COM(2011) 144 final: Roadmap to a Single European Transport Area - Towards a competitive and resource 
efficient transport system 
34 Study on the Completion of an EU framework on LNG-fuelled ships and its relevant fuel provision 
infrastructure: http://ted.europa.eu/udl?uri=TED:NOTICE:347013-2013:TEXT:EN:HTML&tabId=1 

34 

 
 
 
 
 
 
 
                                                            
The use of LNG in transport is an option because of LNG's its high energy density, low 
pollutant emissions and lower greenhouse gas emissions,35 however the overall GHG impact 
of LNG usage will be affected by any emissions ('slip') of methane during filling/bunkering 
and/or operation of engines, and this therefore needs to be minimised36. Similar 
considerations apply to the use of LNG in heat and power supply. 

There is significant potential for GHG impacts to be further reduced through the use in LNG 
fuelled ships or lorries of liquid biomethane (and/or liquid synthetic gas produced from low 
carbon sources), for example through blending with LNG.  

The  overall  environmental  impacts  of  LNG  facilities  can  also  be  reduced  by,  for  example, 
combining regasification facilities with cooling warehouses or other large energy consumers 
who can make use of the excess cooling potential. 

35 Life cycle greenhouse gas intensity according to Directive 2015/652 is for diesel 95,1 gCO2eq./MJ, and for LNG 74,5.  
36 Methane slip is expected to be  largely eliminated in the next generation of LNG-fuelled engines. 

35