Prospects of LNG Markets in the Eastern Partner Countries : final report : January 2020: long version with technical annexes.
Date: 2020-04-24
Institutions: Directorate-General for Energy
Subjects: Eastern Bloc countries, Eastern Partnership, energy grid, energy market, energy policy, energy supply, energy transport, gas, price of energy

 
 
 
 
 
 
 
 
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Nº2018/406588 

Technical Expertise to Assess the Prospects of LNG Markets in the 

Eastern Partner Countries 

This document has been prepared under the terms of the European Union funded project 
PI/2019/406-588/1. 

The content of this document is the sole responsibility of the consortium led by Stantec and 
can in no way be taken to reflect the views of the European Union. This document is prepared 
solely for the use and benefit of the beneficiary countries of the Eastern Partnership and the 
Contracting Authority, the European Union, and neither the consortium led by Stantec, nor the 
authors accept or assume any responsibility or duty of care to any third party.  

©Stantec 2018 

Evangelos Penglis, TL 

Prepared By 

Fotis Thomaidis, KE 

Orest Grynyk, KE 

Reviewer 

Ozlem Duyan 

© European Union, 2020 

Luxembourg: Publications Office of the European Union, 2020 

PDF   ISBN 978-92-76-17892-7   doi: 10.2833/985888   MJ-02-20-245-EN-N 

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BASIC PROJECT DATA 

Project Title 

Project 
ref.no 

Service 
contract no 

Technical  expertise  to  assess  the  prospects  of  LNG  markets  in  the  Eastern 
Partner countries 
PI/2019/406-588/1 

2019/406588 

Contracting Authority: European Commission (FPI) 
Contact persons: 

ENER 

A.3.E-mail: 

Marion Schiller-Probst/ Ewelina Hartstein 
DG 
probst@ec.europa.eu 
Ewelina.HARTSTEIN@ec.europa.eu 
Swati Sain Gupta 
FPI.4 
E-mail: Swati-Sain.Gupta@ec.europa.eu 

marion.schiller-

15.05.2019 

8 Months 

239,990.00 

Date of 
contract 
signature 

Contract 
Duration 

Total 
contracted 
amount 
(Euro) 

Contractor’s name and address: Stantec SA/NV 
Address:  Nysdam  Office  Park,  Avenue  Reine  Astrid 
92, B-1310 La Hulpe, Belgium 

Contact person: Ozlem Duyan 
Telephone number: +32 2 655 22 72 
E-mail: Ozlem.Duyan@stantec.com 
Project Team Leader: Evangelos Penglis 
Telephone number: +30 216 7004070.  
E-mail: evangelos.penglis@vis-consultants.com 

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TABLE OF CONTENTS 
EXECUTIVE SUMMARY ..........................................................................................................10 
1 
INTRODUCTION AND PURPOSE OF THE STUDY ...........................................................19 
2  METHODOLOGICAL APPROACH .....................................................................................21 
2.1 
IDENTIFICATION OF APPLICABLE OPTIONS FOR LNG MARKET DEVELOPMENT PER COUNTRY ...21 
2.2  ANALYSIS OF APPLICABLE OPTIONS FOR LNG MARKET DEVELOPMENT PER COUNTRY ...........24 
2.3  DETAILING AND PRIORITIZATION OF SPECIFIC ACTIONS .........................................................25 
3  LNG MARKET PROSPECTS IN ARMENIA ........................................................................29 
3.1 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................29 
3.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................30 
3.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

33 

3.4  PRIORITIES AND POLICY DIRECTIONS ...................................................................................38 
3.5  PROPOSED PREPARATORY ACTIONS ....................................................................................38 
4  LNG MARKET PROSPECTS IN AZERBAIJAN .................................................................40 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................40 
4.1 
4.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................41 
4.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

42 

4.4  PRIORITIES AND POLICY DIRECTIONS ...................................................................................49 
4.5  PROPOSED ACTIONS ..........................................................................................................49 
5  LNG MARKET PROSPECTS IN BELARUS .......................................................................51 
5.1 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................51 
5.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................52 
5.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

56 

5.4  PRIORITIES AND POLICY DIRECTIONS ...................................................................................62 
5.5  PROPOSED ACTIONS ..........................................................................................................63 
6  LNG MARKET PROSPECTS IN GEORGIA ........................................................................64 
6.1 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................64 
6.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................65 
6.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

73 

6.4  PRIORITIES AND POLICY DIRECTIONS ...................................................................................84 
6.5  PROPOSED ACTIONS ..........................................................................................................85 
7  LNG MARKET PROSPECTS IN MOLDOVA ......................................................................87 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................87 
7.1 
7.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................88 

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7.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

92 

7.4  PRIORITIES AND POLICY DIRECTIONS ...................................................................................94 
7.5  PROPOSED ACTIONS ..........................................................................................................94 
8  LNG MARKET PROSPECTS IN UKRAINE ........................................................................95 
IDENTIFICATION OF APPLICABLE LNG MARKET DEVELOPMENT OPTIONS ................................95 
8.1 
8.2  ASSESSMENT OF VIABILITY OF APPLICABLE LNG MARKET OPTIONS ......................................97 
8.3  PREREQUISITES AND KEY SUCCESS FACTORS FOR POTENTIALLY VIABLE LNG MARKET OPTIONS

113 

8.4  PRIORITIES AND POLICY DIRECTIONS ................................................................................. 126 
8.5  PROPOSED ACTIONS ........................................................................................................ 126 
9  REGIONAL PERSPECTIVES FOR LNG MARKET DEVELOPMENT ............................... 128 
10  RECOMMENDATIONS FOR EU AND EASTERN PARTNERS’ JOINT ACTIONS ......... 131 
ANNEX 1: OVERVIEW OF EASTERN PARTNERS’ GAS MARKETS ................................... 132 
A1.1.  ARMENIA ...................................................................................................................... 132 
A1.2.  AZERBAIJAN ................................................................................................................ 137 
A1.3.  BELARUS ..................................................................................................................... 143 
A1.4.  GEORGIA ..................................................................................................................... 149 
A1.5.  MOLDOVA .................................................................................................................... 156 
A1.6.  UKRAINE ...................................................................................................................... 162 
ANNEX 2: NETBACK ANALYSIS – GAS-TO-GAS COMPETITION ...................................... 172 
A2.1.  NETBACK  ANALYSIS 
IN  CASE  OF  REGASIFIED  LNG  SUPPLIED  VIA  PIPELINE  FROM 
NEIGHBOURING EU LNG TERMINALS ......................................................................................... 172 
A2.2.  NETBACK ANALYSIS IN CASE OF LNG RECEIVING TERMINAL IN EASTERN PARTNER COUNTRY

181 

A2.3.  NETBACK ANALYSIS IN CASE OF LNG SUPPLIED FROM LIQUEFACTION TERMINAL IN BLACK SEA

186 

A2.4.  NETBACK ANALYSIS IN CASE OF LNG SUPPLIED VIA TRUCKS TO A REGASIFICATION TERMINAL 
CONNECTED TO THE TRANSMISSION ........................................................................................... 192 
ANNEX 3: NETBACK ANALYSIS – GAS-TO-OTHER FUELS COMPETITION ..................... 199 
A3.1.  NETBACK ANALYSIS FOR LNG AS FUEL FOR LONG-HAUL TRUCKS ................................... 199 
A3.2.  NETBACK ANALYSIS FOR LNG SUPPLY TO OFF-GRID DISTRIBUTION SYSTEMS .................. 209 
A3.3.  NETBACK ANALYSIS FOR LNG SUPPLY TO OFF-GRID INDIVIDUAL CONSUMERS ................. 217 
A3.4.  NETBACK ANALYSIS FOR LNG AS FUEL FOR SHIPS ......................................................... 222 
ANNEX 4: ECONOMIC ANALYSIS – GAS-TO-GAS COMPETITION .................................... 227 
A4.1.  ECONOMIC ANALYSIS FOR LNG RECEIVING TERMINAL IN EASTERN PARTNER COUNTRY ... 227 
A4.2.  ECONOMIC ANALYSIS FOR REGASIFIED LNG SUPPLIED VIA PIPELINE FROM NEIGHBOURING EU 
LNG TERMINALS ...................................................................................................................... 241 

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A4.3.  ECONOMIC  ANALYSIS  FOR  IN  CASE  OF  LNG  SUPPLIED  FROM  LIQUEFACTION  TERMINAL  IN 
BLACK SEA .............................................................................................................................. 244 
A4.4.  QUANTITATIVE  INDICATORS  FOR  GAS-TO-GAS  COMPETITION  LNG  MARKET  DEVELOPMENT 
OPTIONS’ ASSESSMENT ............................................................................................................. 247 
ANNEX 5: ECONOMIC ANALYSIS – GAS-TO-OTHER FUELS COMPETITION ................... 253 
A5.1.  ECONOMIC ANALYSIS FOR LNG AS FUEL FOR LONG-HAUL TRUCKS ................................. 253 
A5.2.  ECONOMIC ANALYSIS FOR LNG SUPPLY TO OFF-GRID CONSUMERS ................................. 260 
ANNEX 6: KEY LNG INFRASTRUCTURE COST BENCHMARKS ........................................ 263 
ANNEX 7: CURRENCY / UNIT CONVERSIONS .................................................................... 264 

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Annexes 

Annex 1  

Overview of Eastern Partners’ gas markets 

Annex 2 

Annex 3 

Annex 4 

Annex 5 

Annex 6 

Annex 7 

Netback Analysis – Gas-to-Gas Competition 

Netback Analysis – Gas-to-Other Fuels Competition 

Economic Analysis – Gas-to-Gas Competition 

Economic Analysis – Gas-to-Other Fuels Competition 

Key LNG Infrastructure Cost Benchmarks 

Currency / Unit Conversions 

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LIST OF ACRONYMS 

ACB 

ACER 

ACG 

ADR 

AERA 

AGRI 

ANRE 

ATI 

Bcm 

Ananiev-Cernăuți-Bogorodcianî Pipeline 

Agency of the Cooperation of Energy Regulators 

Azeri-Chirag-Gunashili Pipeline 

Accord  européen  relatif  au  transport  international  des  marchandises 
Dangereuses par Route 
Azerbaijan Energy Regulatory Agency 

Azerbaijan-Georgia-Romania Interconnector 

National Energy Regulatory Agency 

Ananiev-Tiraspol-Ismail Pipeline 

Billion Cubic Meters 

BELAZ 

Belarusian Automobile Plant 

BP 

British Petroleum 

CAPEX 

Capital expenditure 

CBA 

ChNG 

CHP 

CNG 

Cost Benefit Analysis 

Chornomornaftogaz 

Combined heat and Power 

Compressed Natural Gas 

DESFA 

Hellenic Gas Transmission System Operator S.A. 

DG 

DSO 

EC 

EIA 

Directorate-General 

Distribution System Operator 

European Commission 

Energy International Agency 

ENPV 

Economic Net Present Value 

ENTSOG 

European Network of Transmission System Operators for Gas 

ERR 

EU 

EUD 

Economic Rate of Return 

European Union 

European Union Delegation 

FSRU 

Floating Storage Regasification Unit 

FWC 

FID 

GCV 

GDP 

Framework Contract 

Final Investment Decision 

Gross Calorific Value 

Gross Domestic product 

GEOSTAT 

National Statistics Office of Georgia 

GGTC 

Georgian Gas Transportation Company 

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GHG 

GIPL 

GNERC 

GOGC 

HFO 

HH 

IMO 

IP  

JRC 

JSC 

KE 

Technical Expertise to Assess the Prospects of LNG Markets in the 

Eastern Partner Countries 

Green House Gas 

Gas Interconnection Poland–Lithuania 

Georgian National Energy and Water Supply Regulatory 

Georgian Oil and Gas Corporation 

Heavy Fuel Oil 

Households 

International Maritime Organization 

Interconnection Point 

Joint Research Centre 

Joint-Stock Company 

Key Expert 

L-CNG 

Liquified-to-Compressed Natural Gas 

LFO 

LLC 

LNG 

LPG 

MAZ 

Mcm 

MGO 

NEURC 

NGVA 

NPP 

OCh 

OPEX 

PECI 

PSO 

PSRC 

RI 

SCP   

SCPX 

ȘDKRI 

SOCAR 

SoS 

SSLF 

SSO 

TL 

TPA 

Light Fuel Oil 

Limited Liability Company 

Liquified Natural Gas 

Liquified Petroleum Gas 

Minsk Automobile Plant 

Million Cubic Meters 

Marine Gas Oil 

National Energy and Utilities Regulatory Commission 

Natural & bio Gas Vehicle Association 

Nuclear Power Plant 

Odesa-Chișinău Pipeline 

Operation expenditure 

Project of Energy Community Interest 

Public Service Obligation 

Public Services Regulatory Commission 

Razdelinaia-Ismail Pipeline 

South Caucasus Pipeline 

South Caucasus Pipeline Extension 

Șebelinca-Dnepropetrovsk-Krivoi Rog-Ismail Pipeline 

State Oil Company of Azerbaijan Republic 

Security of Supply 

Small Scale Liquefaction Facility 

Storage System Operator 

Team Leader 

Third Part Access 

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TPAO 

TPP 

TSO 

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Turkish Petroleum Corporation 

Thermal Power Plant 

Transmission System Operator 

TYNDP 

Ten Year Network Development Plan 

UGS 

UGS 

UGV 

UN 

UTG 

VAT 

VoLL 

Underground Gas Storage 

Underground Gas Storage 

Ukrgasvydobuvannya 

United Nations 

Ukrtransgaz 

Value Added Tax 

Value of Lost Load 

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Executive Summary 

Introduction 

In May 2019, DG Energy commissioned Stantec to carry out a Study to assess the prospects of 
developing  LNG  markets  in  Eastern  Partner  countries,  so  as  to  enhance  the  cooperation  and 
further the energy market integration between the Eastern Partner and the EU.  The Study was 
specified  in  the  Concept  Note  for  the  Eastern  Partnership  LNG  Network  Group  that  was 
established with the aim to assess the economic and political opportunities for LNG in the Eastern 
Partner  countries.  The  specific  objectives  of 
formulation  of 
recommendations for development of LNG markets country-by-country and for the region as a 
whole,  and  the  identification  of  actions  that  improve  market  functioning,  competition,  new 
infrastructures, and foster cooperation within the Eastern Partnership region.  This is the summary 
of the Final report of the Study that was completed in January 2020.  

the  Study 

include 

the 

LNG Market Development Options 

The Study involved the Consultants in identifying potentially applicable options for LNG market 
development for each Eastern Partner country, based on characteristics and market conditions 
relevant  to  each  country.  Not  all  gas-to-other  fuels  competition  options  are  applicable  to  all 
Eastern Partner countries.   

Applicable  LNG  options  are  grouped  under  two  broad  categories,  those  enabling  gas-to-gas 
competition and those enabling gas-to-other fuels competition.  Gas-to-gas competition occurs 
when (regasified) LNG competes against natural (piped) gas for customers that are connected to 
the gas transmission system.  In gas-to-other fuels competition, LNG competes with other fuels 
(diesel, MGO, HFO etc.) for customers that do not currently use gas and are not connected to the 
gas network.  Depending on the end-use, LNG may be used by customers in liquid form (e.g. as 
fuel for trucks) or regasified and used in gaseous form (e.g. by off-grid consumers).   

There are several options with which LNG may be introduced to a country in the case of gas-to-
gas  competition;  one  option  is  for  LNG  to  be  sourced  from  a  third-country  terminal,  and 
transported to the Eastern Partner country in regasified form through pipes for final consumption 
by  target  customers.  Another  option  is for  an  LNG  receiving  terminal  to  be  built  in  an  Eastern 
Partner  country  with  sea  access  to  supply  regasified  LNG  to  customers  connected  to  the  gas 
network.    Alternatively,  LNG  either  from  the  in-country  or  outside  country  terminal  can  be 
transported via trucks or rail to grid connected customers, as ‘virtual’ gas pipelines. Swaps are 
also a possibility for introducing LNG, in case it is feasible to do so contractually and economically. 
For example, for an Eastern Partner country with no sea access to purchase LNG for physical 
delivery to a terminal in another country, and another party to off-take this LNG in exchange for 
piped gas that is physically delivered to the Eastern Partner country concerned.   

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In the case of gas-to-other fuels competition, LNG is used directly as a fuel by trucks, or by ships 
or by agricultural and mining customers who can use LNG as fuel for processes (e.g. drying etc.) 
or heavy equipment (tractors, graders etc.).   One common feature in these end-uses is the need 
for  ‘virtual’  gas  pipelines  delivering  LNG  to filling  stations  or  to  the  customer’s  storage facility. 
Alternatively,  regasified  LNG  can  be  used  by  different  types  of  off-grid  customers  (industrial, 
commercial,  remote  towns  etc.)  for  various  needs  that  were  traditionally  fulfilled  by  alternative 
fuels e.g. heating, drying, turbines, furnaces etc.). In these cases, customers are required to have 
regasification facilities.  

Approach  

The work involved research into Eastern Partner countries, and particularly their gas and energy 
markets, and identification of potentially applicable LNG market development options.  Field visits 
were undertaken to all Eastern Partner countries from June to September 2019. The objective 
was  to  discuss  with  key  stakeholders  in  each  country  the  current  situation  and  prospects  for 
developing markets for LNG, their policies and interests, and barriers and prerequisites for LNG 
market development, to reach a consensus on the LNG options deemed potentially applicable for 
each Eastern Partner Country and merit further analysis. During the field visits the Consultants 
presented  information  to  enhance  gas  stakeholders’  awareness  on  EU  LNG  strategy,  market 
development,  demand,  supply,  prices  and  key  infrastructure,  operational  modalities  of  LNG 
terminals and ‘virtual’ gas pipelines involving LNG.  

The applicable LNG options that were identified following the field visits for further analysis are 
shown in the following Table.  The options were presented to and confirmed with Eastern Partner 
countries  representatives during the third  Eastern Partnership  LNG Gas Network Workshop in 
Kiev, in September 2019.   

The Consultants proceeded to analyse the price competitiveness of the applicable LNG market 
development options for each country, using Netback Analysis, with the objective of identifying 
the  options  that  are  deemed  economically  viable.  The  Netback  Analyses  carried  out  are  high-
level, using proxies of actual costs and based on international benchmarks and assumptions. In 
cases  where  market  demand  data  were  not  available  and  netback  analysis  could  not  be 
reasonably performed, the analysis focused on identifying the ‘breakeven’ demand in the Eastern 
Partner  country  that  could  render  the  option  viable  under  assumed  price  and  cost  conditions 
throughout the supply chain. 

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The results of the Netback Analysis, as well as the underlying assumptions were included in the 
November  2019  Interim  report  of  the  Study  that  was  shared  with  Easter  Partner  countries  for 
views  and  comments.  Feedback  and  additional  information  provided  by  the  Eastern  Partner 
countries,  as  well  as  during  the  fourth  Eastern  Partnership  LNG  Gas  Network  Workshop  in 
Świnoujście in December 2019 were taken into account in the Final Report. The Study includes 
a high-level Cost Benefit analysis for selected LNG options, to assess additional benefits accruing 
to  economy  and  society.    This  CBA  was  carried  out  for  all  potentially  applicable  gas-to-gas 
competition LNG market development options in each Eastern Partner country, and for those gas-
to-other  fuels  competition  options  deemed  to  be  economically  viable  in  each  Eastern  Partner 
country. Furthermore, the Consultants analyzed and highlighted all key prerequisites and success 
factors  for  the  implementation  of  viable  LNG  options,  and  formulated  proposals  for  the 
prioritization of economically viable options in each country and for the actions that need to be 
taken by policy makers in each country to foster development of the selected options.  Regional 
perspectives for  LNG market  development  are  also included  in the  Final  Report,  together  with 
relevant  regional  and  sub-regional  policy  initiatives  and  joint  EU-Eastern  Partners  countries 
actions that could be undertaken.   

Findings 

Armenia 

The  use  of  LNG  as  engine  fuel  for  trucks  is  the  only  applicable  option  identified  for  Armenia. 
Supply of LNG in Armenia is possible through the development of an in-country mini liquefaction 
facility, or in case, an LNG receiving terminal with truck loading facilities is developed in Georgia.  

The analysis performed shows that the LNG option using an in-country mini liquefaction facility, 
which requires significant infrastructure investments, is potentially viable for Armenia in case at 
least 340 LNG-fuelled trucks refuel in the country (corresponding to approx. 15,300 m3 LNG/yr). 
Supplies from a potential LNG receiving terminal in Georgia lower the supply chain costs, and 
thus a smaller minimum market size of at least 135 LNG-fuelled trucks (approx. 6,000 m3 LNG/yr) 
is necessary for the option to be attractive. However, establishment of a supply chain based on 
the terminal is beyond Armenia’s control, as the infrastructure is subject to a decision by Georgian 
stakeholders, and dependent on a number of factors controlled by external parties. 

Regardless of the source of LNG, the interest of sufficient truck owners to switch to LNG, and the 
attraction of investments to develop filling stations are critical to initiate a market for the use of 
LNG as engine fuel for trucks.   

Development of an LNG supply chain using a mini liquefaction facility could be done in a short-
term horizon, as it only involves decisions by local actors. In contrast, supplies of LNG from a 
receiving terminal in Georgia are assessed to be longer-term, due to uncertainties surrounding 
the terminal investments.  

Considering that Armenia has a sizable fleet of trucks involved in local, regional and international 
transport, the minimum number of trucks required for  viability of the option appears feasible at 
first sight and therefore this option merits further investigation, to assess its feasibility in detail. 
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The policies and actions to facilitate development of the market, could encompass the formulation 
of a national policy framework for the use of LNG in trucks, ensuring that the legal and regulatory 
framework conducive to the development of an LNG supply chain, and consideration of incentives 
to promote the use of LNG. 

Azerbaijan 

The use of LNG as engine fuel for trucks, with LNG supplied from an in-country mini liquefaction 
facility, is an applicable option identified for Azerbaijan. However, the very low, subsidised, diesel 
price  is  an  obstacle  for  LNG  competitiveness,  and  costs  for  developing  an  LNG  supply  chain 
cannot be recovered.   

The  use  of  LNG  as  engine  fuel  for  ships  operating  in  the  Caspian  Sea,  by  developing  LNG 
bunkering  infrastructure  in  the  Baku  port,  is  another  potentially  applicable  option.  The 
attractiveness  of  switching  to  LNG  should  be  examined  on  a  case-by-case  basis,  for  each 
individual case of ship, as it depends on a number of vessel-specific factors (size and type, age, 
service  area,  fuel  used,  refuelling  pattern,  prices  of  competing  fuels,  etc.).  Such  a  detailed 
analysis  should be  undertaken  in the future,  in  case  the Government  of Azerbaijan  decides to 
pursue this option. 

Although Azerbaijan has 95% coverage of population through its current network, the Government 
of Azerbaijan is interested in the option of establishing LNG virtual pipelines to supply gas to off-
grid remote areas, within the frame of its target of 100% gasification of the country. This option 
was  not  analyzed  in  this  Study,  as  no  data  was  made  available  on  the  fuel  consumption  and 
demand characteristics of remote areas.  

In  case  the  Government  decides  to  move  ahead  with  the  development  of  LNG  options  for 
environmental reasons, it should examine in detail the options, and formulate appropriate policies 
and  actions  to  promote  LNG.  Such  policies  and  actions  should,  at  a  minimum,  establish  a 
framework making LNG more attractive (e.g. subsidizing LNG prices or lifting prices for diesel), 
perform the legislative and regulatory changes necessary to allow development of an LNG supply 
chain, and undertake initiatives to promote the use of LNG.  

Belarus 

The use of LNG as engine fuel for trucks is an option that could be potentially viable for Belarus, 
in case LNG is sourced from the reloading station in Klaipeda (the closest facility to the country) 
and price differential of LNG and diesel remains at current levels. In this case, over 200 LNG-
fuelled trucks would need to refuel in the country (corresponding to approx. 9,300 m3 LNG/yr) for 
the LNG market to develop. Considering that Belarus has a sizeable fleet of local and imported 
international  long  haulage  trucks,  and  local  manufacturing  of  LNG-fueled  trucks  could  lower 
switching costs, the minimum market size appears to attainable at first sight and therefore merits 
more detailed examination.  

The LNG option could be developed over a short-term horizon, provided that truck owners are 
interested to switch to LNG, and investments in filling stations are implemented. To promote the 

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establishment of the LNG market, the Government could formulate a national policy framework 
for the use of LNG in transport, and undertake actions, aiming to establish a legal and regulatory 
framework conducive to the development of an LNG supply chain and to providing incentives for 
the use of LNG. 

Another potentially applicable option is the use of LNG as engine fuel for vessels operating in the 
Belarusian waterways, by developing LNG bunkering infrastructure in inland ports of Belarus. The 
applicability  of  the  option  appears  to  be  limited,  due  to  the  small  size  and  limited  utilization  of 
vessels  vis-à-vis  investment  requirements.  Nevertheless,  in  case  the  Government’s  policy 
priorities  for  the  shipping  sector  promote  LNG,  it  should  undertake  contextualized  analysis,  to 
identify whether there are any types of vessels for which switching to LNG may be attractive. 

Georgia 

The  swap  of  regasified  LNG  landing  at  a  terminal  in  Turkey,  Greece  or  Italy  with  piped  gas 
delivered to Georgia through its offtake of the SCP is a potential option that could provide Georgia 
with indirect access to LNG. This option is conditional upon the interest by the involved parties to 
conclude a swap deal, the availability of LNG at prices that are conducive to the viability of the 
exchange, and the lack of any contractual barriers that would obstruct access to the SCP. In case 
these  conditions  are  met,  negotiations  for  swaps  with  relevant  stakeholders  could  be  quickly 
initiated, as the option does not require development of new infrastructures. 

Development of an LNG receiving terminal in Georgia, is a potentially viable option only in case 
the price differential between LNG and piped gas imports is at least 35 EUR/1000 m3 (for high 
utilization of the terminal) or at least 85 EUR/1000 m3 (for low utilization of the terminal). These 
conditions  cannot  be  met  under  the current market situation,  but  could  be triggered  in  case  of 
price hikes in the new supply contracts with Azerbaijan, which are due to renewal after 2026. A 
critical/on-off prerequisite for the implementation of the terminal is the absence of any constraints 
for LNG vessels to pass through the Bosporus Straits, while key prerequisites for establishment 
and viability are the commitment of sufficient market players to use the terminal (so as to achieve 
high capacity utilization), and the availability of financing. On account of these conditionalities, the 
terminal  is  a  long-term  option,  the  final  condition  for  which  would  require  conclusion  of 
negotiations with Turkey for the passage of LNG vessels through the Straits, and a successful 
binding market test securing market interest.  

Development of a liquefaction and export terminal in Georgia, receiving gas from Azerbaijan and 
potentially  Central  Asia,  is  an  option  for  LNG  supplies  to  other  Eastern  Partners,  particularly 
Ukraine and Moldova, provided that a receiving terminal is developed in Ukraine. Critical/on-off 
prerequisites for developing this infrastructure are the availability of sufficient long-term supply of 
Caspian gas to the terminal and long-term sales contracts of the produced LNG to customers. As 
all Azeri gas production from developed fields has already been contracted and there is no access 
to supplies of gas from Central Asia, the liquefaction terminal could only be considered in a long-
term  horizon.  Furthermore, the  high-level  analysis  performed  has  shown  that for  the  supply  of 
LNG to be viable in Ukraine, the price of Caspian gas at the liquefaction terminal would have to 

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be under 115 EUR/1000 m3, i.e. 85 EUR/1000 m3 lower than the current import price of Azeri gas 
in Georgia.    

The  use  of  LNG  as  engine  fuel  for  trucks  is  a  potentially  viable  option  for  Georgia.  In  case  a 
receiving terminal is developed, the option could develop with a market of only a60 LNG-fuelled 
trucks  (corresponding  to  approx.  2,800  m3  LNG/yr),  while  a  minimum  of  100  trucks  would  be 
required  in  case  LNG  is  sourced  from  a  liquefaction  and  export  terminal  (approx.  4,600  m3 
LNG/yr). Due to the uncertainties linked to the development of both the aforementioned terminals 
and the long term maturity of such investments, the LNG market could be established within a 
shorter-term horizon, in case a mini liquefaction facility is developed; however, in this case a large 
number of trucks is required for viability of the option (280 trucks, corresponding to approx. 12,600 
LNG/yr),  due to  the  higher  costs  of the  supply  chain.  Similar  to  other  countries, the  interest  of 
sufficient  truck  owners  to  switch  to  LNG,  and  the  attraction  of  investments  to  develop  filling 
stations are critical to initiate the LNG option. Considering that Georgia is a regional trade and 
transit hub, though its ports, the minimum number of trucks required appears feasible at first sight 
and  therefore  this  option  merits  further  investigation,  to  assess  in  detail  its  feasibility.  The 
Government  could  consider  formulating  appropriate  policies  and  actions  to  promote  LNG  in 
transport, including a national policy framework for the use of LNG in road transport, legal and 
regulatory changes to allow development of an LNG supply chain, and provision of incentives to 
promote switching to LNG. 

Another  applicable  option  identified  for  Georgia  is  the  supply  of  LNG  to  off-grid  remote  areas 
targeted for gasification. This option is considered non-viable, as due to the low price of firewood 
(the main competing fuel in these regions), switching to natural gas is not competitive. 

Moldova 

The  supply  of  regasified  LNG  from  neighbouring  EU  LNG  terminals  is  an  applicable  option 
identified for Moldova. Although the option is not viable, due to the low gas price in the Moldovan 
market, that renders LNG non-competitive, the supply of regasified LNG, even at small volumes, 
offers a new source that can have a significant impact in the country’s security of supply. The 
option could be implemented over a short-term horizon, as it does not require development of a 
new infrastructure, and could merit further examination from the Moldovan stakeholders, from a 
security of supply perspective. 

LNG  imports  through  a  Ukrainian  receiving  terminal  (with  LNG  either  coming  through  the 
Bosporus Straits or liquefied at a terminal in Georgia) could also enhance Moldova’s security of 
supply.  However,  this  option  is  heavily  dependent  upon  the  significant  uncertainties  of  the 
Ukrainian terminal development.  

Another  applicable  option  identified  for  Moldova  is  the  use  of  LNG  for  peak  shaving  at  the 
country’s CHP stations as a back-up supply source. This option, albeit not being viable, as it does 
not provide a competitive source to piped gas, can potentially enhance security of energy supply. 
In this respect, the economic costs and benefits for developing this option should be considered 
(such an analysis was not carried out within the frame of this Study, due to lack of relevant data).    

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Ukraine 

The  supply  of  regasified  LNG  from  neighbouring  EU  LNG  terminals  is  an  applicable  option 
identified  for  Ukraine.  Viability  of  the  option  requires  the  spread  between  LNG  price  at  the 
terminals and prices of imported supplies from existing sources to be at least of the order of 40 – 
50 EUR/1000 m3 (depending on the route). It is marginally viable in case the LNG price is around 
200 EUR/1000 m3, and import prices in Ukraine are close to historic winter prices. However, in 
case the spread between LNG and import prices is wide enough, the market may procure LNG 
on an opportunistic basis. 

Development  of  an  LNG  receiving  terminal  in  Ukraine  is  only  viable  in  case  there  is  a  price 
differential of at least 30 EUR/1000 m3 between LNG supplies arriving at the terminal and imports 
from EU, and a high terminal utilization (over 50%) is secured. A critical/on-off prerequisite for the 
implementation of the terminal is the absence of any constraints for LNG vessels to pass through 
the Bosporus Straits, while key prerequisites for establishment and viability are the commitment 
of sufficient market players to use `the terminal (so as to achieve high capacity utilization), and 
the availability of financing. On account of these conditionalities, the terminal is a medium to long-
term option, the final condition for which would require conclusion of negotiations with Turkey for 
the passage of LNG vessels through the Straits, and a successful binding market test securing 
market interest.  

Another option examined, aiming at gas-to-gas competition, is the supply of LNG via trucks to 
consumers currently connected to the transmission system. Analysis has shown that this option 
is not viable, as the costs associated with this LNG supply chain render a regasified LNG price 
which is not competitive compared to piped gas.  

The use of LNG as engine fuel for trucks, with LNG sourced from the neighbouring terminals is a 
potentially viable option for Ukraine, requiring a market of at least 60 LNG-fuelled trucks refuelling 
in the country (corresponding to approx. 2,700 m3 LNG/yr). As Ukraine appears to have a sizable 
international  long-haul  traffic  (export/imports  and  transit)  the  minimum  market  size  seems  to 
attainable at first sight and therefore merits more detailed examination. The LNG option could be 
developed over a short-term horizon, provided that truck owners are interested to switch to LNG, 
and  investments  in filling stations  are  implemented. To  promote the  establishment  of  the  LNG 
market,  the  Government  could  formulate  a  national  policy  framework  for  the  use  of  LNG  in 
transport,  and  undertake  actions,  aiming  to  complete  the  legal  and  regulatory  framework 
conducive to the development of an LNG supply chain and to providing incentives for the use of 
LNG. 

The use of LNG as engine fuel for ships operating in the Black Sea and Ukrainian waterways is 
another  potentially  applicable  option  for  Ukraine.  This  option  would  nevertheless  require 
stakeholders to undertake contextualized analysis, as LNG use is not appropriate for all ships and 
would  depend  on  technical  considerations,  utilization  and  fuel  economics  and  environmental 
requirements. This option could be developed over a medium-term horizon, as it would require 
involvement and large investments from ship owners for a diverse number of vessels. 

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Supply of LNG to individual off-grid consumers in Ukraine (such as small to medium agriculture, 
construction or mining sites) can be viable under conditions, and should be assessed on a case-
by-case basis, as viability depends on the number, size and characteristics of these consumers. 
Switching to LNG is primarily the consumer’s decision, and can be implemented over a short-term 
horizon, as LNG can be sourced from existing terminals. To facilitate the development of LNG 
supply  chains,  the  Government  policy  should  aim  to  completing  the  legal  and  regulatory 
framework conducive to LNG.  

The  use  of  LNG  virtual  pipelines  as  an  alternative  to  replacement  of  old  medium  pressure 
pipelines in the Ukrainian distribution systems was identified as an applicable option. However, 
the large costs associated with developing the LNG infrastructure render this option as not viable 
and less attractive compared to installing a new pipeline. 

Another  applicable  option  identified  for  Ukraine  is  the  use  of  LNG  virtual  pipelines  to  develop 
remote gas fields. Analysis of this option was not carried out within the frame of this Study, due 
to the lack of data on Ukraine’s remote fields. 

Regional Perspectives and Actions 

Some of the identified potentially viable options for LNG market development are of interest to 
two or more Eastern Partner countries. An LNG receiving terminal in Ukraine can supply LNG to 
Moldova, and opens the way for a smaller LNG terminal in Georgia (that could also be established 
independently).    Potential  development  of  a  liquefaction  and  export  terminal  in  Georgia  would 
allow  exports  of  Caspian  gas  though  the  Black  Sea  and  foster  development  of  an  alternative 
corridor for LNG supplies to Eastern Partner countries, notably Ukraine and Moldova.  There are 
also  opportunities  for  cooperation  between  Eastern  Partner  countries  on  smaller-scale 
infrastructure, such as the development of a regional network of LNG filling stations, to enhance 
accessibility  of LNG to  long-haul trucks  operating  in  the region  and  provide  incentives to  truck 
owners  to  switch  to  LNG,  an  option  which  is  of  interest  to  most  Eastern  Partner  countries 
(Armenia,  Azerbaijan,  Belarus,  Georgia,  Ukraine).    Furthermore,  the  development  of  an  LNG 
receiving or liquefaction and export terminal in Georgia would also allow Armenia access to LNG 
supplies, facilitating the development of an LNG market.   

On a regional level, a number of actions can be considered to foster development of the above 
options, including the creation of sub-committees under the Eastern Partnership LNG Network, 
to  facilitate  dialogue,  coordination  and  initiatives  on  key  LNG  issues  (technical  &  standards, 
regulatory,  market,  etc.).  Harmonization  of  rules,  regulations  and  standards,  for  LNG-fuelled 
trucks,  and  for  trucks  transporting  LNG,  can  also  for  benefit  from  regional  coordination  and 
cooperation, as well as the preparation of regional development plan for the establishment of LNG 
filling stations in the Eastern Partner countries. On a sub-regional level, Georgia and Ukraine can 
consider  undertake  joint  initiatives  for  resolving  the  Bosporus  Straits’  constraints,  whereas 
Armenia, Azerbaijan and Georgia can jointly consider the potential for co-development of a small-
scale liquefaction facility to supply LNG to trucks in the Caucasus. 

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EU and Eastern Partners Joint Actions  

Eastern Partner countries would benefit from the experience, practices and lessons learned  of 
EU  LNG  markets  and  stakeholders,  and  several  joint  actions  could  be  considered  to  catalyse 
market  development  in Eastern  Partner countries.   These joint  actions  include  the creation  of 
sub-committees under the Eastern Partnership LNG Network, to facilitate dialogue, coordination 
and initiatives on key LNG issues (technical & standards, regulatory, market, etc.).  Other actions 
involve the organised transfer of knowledge from EU counterparts to Eastern Partners, on LNG 
technologies,  on  the  appropriate  legislative  and  regulatory  framework,  technical  rules  and 
standards for all LNG related infrastructure and equipment etc.  Such a transfer can be facilitated 
by another joint action, namely the development of a common IT platform for knowledge sharing 
of materials relevant to LNG markets.  The experience the EU gained through the Blue Corridor 
initiative could also from a model case for developing a similar initiative for the use of LNG in the 
transport sectors of Eastern Partners.  Finally, the EU can consider the possibilities to provide co-
financing for selected projects of common interest through the European Network Instrument, or 
other financing mechanisms. 

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1  Introduction and Purpose of the Study 
The overall objective of the Study is to further develop the co-operation and integration between 
the Eastern Partner Countries and the EU in assessing and developing the potential of LNG in 
the gas markets of the region.  Specific objectives of the Study are to: 

  Assess current situation in Eastern Partners’ gas markets and identify barriers for LNG; 

  Formulate recommendations for development of LNG markets country-by-country and 

for the region as a whole; 

  Strengthening  awareness  of  gas  stakeholders  in  Eastern  Partner  countries  on 
technical, market, and regulatory aspects of LNG, and particularly the use of LNG in 
the EU;  

 

Identify  specific  actions  to  enhance  trading,  promote  new  infrastructure,  improve 
market  functioning  and  competition,  fostering  cooperation  within  the  Eastern 
Partnership region; 

  Further EU’s Energy Dialogue with the Eastern Partner countries in the area of LNG. 

During  the  Study,  the  Consultants  identified  potentially  applicable  options  for  LNG  market 
development in each Eastern Partner country.  Field visits were undertaken to all Eastern Partner 
countries, in the period of June to September 2019.  The objectives of these visits were twofold:  

 

 

to enhance gas stakeholders’ awareness on EU LNG strategy, market development, 
demand, supply, prices and key infrastructure, operational modalities of LNG  terminals 
and ‘virtual’ gas pipelines involving LNG, and  

to  discuss  with  stakeholders  in  each  country  the  current  situation  and  prospects  for 
developing  markets  for  LNG,  the  barriers  and  prerequisites  for  LNG  market 
development,  and  to  reach  a  consensus  on  the  LNG  market  development  options 
deemed potentially applicable for the country that merit further analysis.  

Netback analysis was then carried out on all potentially applicable options in each country, so as 
to  shortlist  the  options  that  are  considered  to  be  ‘price  competitive’,  and  hence  economically 
viable.  Netback  analysis  determines  what  should  the  LNG  price  be  at  the source (LNG  import 
terminal,  small/mini  liquefaction  plan  etc.)  so  that  when  all  the  costs  of  transporting  and 
transforming  the  LNG  to  reach  the  target  end  consumer  are  added,  the  price  of  LNG  to  the 
customer is competitive compared to the price the customer pays now for alternative competing 
fuels.   

It is noted that the netback analyses carried out in the study are high-level, using proxies of actual 
costs and based on international benchmarks and assumptions. All calculations have been made 
using latest available data concerning market prices, consumption levels and LNG supply costs. 
Sensitivity analysis has been used to assess the robustness of the results in fluctuations of key 
parameters.  Dynamic  supply-demand  conditions  were  not  examined,  and  contextualization  of 
infrastructure  costs  and  other  parameters  was  limited  by  the  available  data.  In  cases  where 
market demand data were not available and netback analysis could not be reasonably performed, 

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the analysis focused on identifying the ‘breakeven’ demand in the Eastern Partner country that 
could render the option viable under assumed price and cost conditions throughout the supply 
chain. The Study analysis is thus considered preliminary, and the results and conclusions are not 
meant  to  be  definitive  but  to  highlight  the  LNG  market  development  options  that  merit  further 
consideration and detailed analysis by the Eastern Partner countries to assess in full their viability 
and to formulate their policies accordingly. 

A high-level Cost Benefit analysis was carried out for selected LNG options, to assess the benefits 
accruing to economy and society.  CBA was carried out for all potentially applicable gas-to-gas 
competition LNG market development options in each Eastern Partner country, and for those gas-
to-other  fuels  competition  options  deemed  to  be  economically  viable  in  each  Eastern  Partner 
country. Key prerequisites and success factors for viable options are highlighted, and a proposed 
prioritization of the economically viable options and the actions that need to be taken, in terms of 
timing  and  ease  of  implementation,  is  provided  for  each  Eastern  partner  country.  Regional 
perspectives for LNG market development are considered, and relevant policy initiatives and joint 
actions are also proposed.  

Finally,  we  would  like  to  note  that  the  LNG  industry  is  undergoing  significant  challenges 
related  to  methane  emissions.    Although  natural  gas  is  considered  to  be  a  ‘cleaner’  fuel  in 
terms  of  CO2  emissions  compared  to  oil  and  coal,  methane  emissions  through out  the  gas 
supply  chain  caused  by  leakages,  releases  of  gas  and  flaring  of  gas,  are  considerable.  
Methane is a more potent greenhouse gas than CO2, as one tonne of methane absorbs 84 to 
87 times more energy than one tonne of CO2, for the first 20 years after being emitted to the 
atmosphere.  IEA1 estimates 2017 methane emissions from the oil and gas sector to be close 
to  80  Mt  (or  2.4  billion  tonnes  of  CO2  equivalent),  and  considers  that  45%  of  the  methane 
emissions could be avoided with measures that would have no net cost. There is a high degree 
of uncertainty concerning the level of methane emissions from the LNG supply chain, due to 
lack of data. Methane emissions from the LNG supply chain could be higher than natural gas, 
in  case  there  are  inefficiencies  of  treatment  of  ‘boil-off  gas’  during  the  LNG  liquefaction, 
transport and storage processes.   Additionally, emissions of unburnt methane (known as the 
‘methane  slip’)  occur  during  LNG  end-use  as  fuel  (LNG  powered  ships  and  trucks).  The 
challenges  faced  by  the  LNG  industry  to  reduce  methane  emissions,  and  the  relevant 
dilemmas facing policy makers regarding the environmental standing of LNG vis-à-vis other 
fuels, are outside the scope of this study. 

1 IEA, Tracking Fuel Supply, Methane Emissions from Oil and Gas, November 2019 

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2  Methodological Approach 
In this Section, we discuss our methodological approach to implementing the Study. More detailed 
elements concerning the Netback Analysis are provided in Annexes 2 and 3. 

The overview of the approach is shown in Figure 1 below. The main methodological steps and 
their sequence are described next. 

Figure 1 Overview of methodological approach 

2.1  Identification of applicable options for LNG market 
development per country  
Hypotheses on potential options for LNG market development were formulated for each Eastern 
Partner country on the basis of desktop countries analysis. These hypotheses were discussed 
and ‘tested’ with stakeholders in Eastern Partner countries during the field visits, as well as during 
the September Eastern Partnership LNG Network Group Workshop in Kyiv. Taking into account 
feedback  received  from  stakeholders,  the  LNG  market  development  options  in  each  Eastern 
Partner country, considered as potentially applicable, were shortlisted for further analysis.   

LNG market development options for each country are grouped under two different categories.  
The first category concerns gas-to-gas competition, i.e. cases where LNG could compete against 
natural  (piped)  gas  for  customers  that  are  connected  to  the  gas  transmission  system.    In  this 
category, LNG constitutes an additional supply source or supply route of gas for the country.  Gas-
to-gas competition requires LNG to be regasified before it is used by final customers.   

The second category involves LNG in competition with other fuels, for customers that currently 
do not use gas and are not connected to the gas network.  Depending on the use, LNG may be 
directly used by customers in its liquid form (e.g. use in transport as fuel for trucks) or regasified 
and used in gaseous form (e.g. by off-grid consumers).  In gas-to-other fuels competition, LNG 
would have environmental benefits (reduction of GHG emissions) in case LNG is used in the place 

21 

3rdEaP LNG Network Workshop (Kiev, 20/9/19)Analysis of applicable options4thEaP LNG Network Workshop (Świnoujście, Dec. 2019)Detailing and prioritization of specific actionsFinal report: Dec. 2019 Stakeholder event: Q12020Identification of applicable LNG market development optionsStart: end of May 2019•Desktop research •Development of initial hypotheses on LNG options•Validation of hypotheses during field visits and EaP workshop•Shortlisting οf applicable options for further analysis•Collection of required data•Definition of  supply chain modalities and cost estimation for selected options•Assessment of price competitiveness (netback analysis) for selected options•Monetizing benefits of the selected options•High-level cost-benefit analysis of price competitive options•Assessment of prerequisites and key success factors•Option prioritization & recommendations (including regional cooperation) 
 
 
 
 
 
 
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of more polluting fuels (e.g. diesel, heating oil, LFO/HFO etc.).  For Gas-to-other fuels competition 
options  to  be  potentially  applicable  in  any  Eastern  Partner  country,  LNG  (or  gas  derived  from 
LNG) has to be competitive against prices of competing fuels.   

Table 1 lists the main LNG development options under each of the two cases2.   

Table 1: LNG Market Development Options under Gas-to-Gas and Gas-to-Other Fuels Competition  

Competition 
Case 

Options for introducing LNG 
to the market 

Main Uses of LNG 

LNG Benefits 

Gas-to-gas 
competition 

  Pipelines (receiving gas of 

  LNG is regasified and transported 

  Gas price reduction  

LNG origin)  

for final consumption  

  Security  of  supply 
benefits  (mitigating 
impact  of  disruption 
as 
of 
a 
supplier/route 
diversification) 

result 

  LNG receiving Terminal 

with regasification facility 

  LNG trucks and trains 

supplying LNG to existing 
natural gas grid-connected 
customers)  

  Swaps (pipeline gas for 

LNG)  

Gas-to-
other fuels 
competition 

  LNG  receiving  Terminal 
with  bunkering  and  lorry 
loading facilities 

  LNG 

trucks  and 
trains 
(supplying  LNG  to  new 
off-grid customers)  

  Small  Scale  Liquefaction 
Facilities  (liquification  of 
piped  gas  and  supply  to 
customers via LNG trucks 

  Trucks that use LNG as fuel  

  Energy 

cost 

reduction 
(substitution of other 
fuels  by  less  costly 
LNG)  

  Environmental 

benefits  (differential 
in  greenhouse  gas 
emissions  by  using 
gas  as  opposed  to 
other fuels) 

  Ships that use LNG as fuel 

  Agriculture  and  Mining  customers 
that  use  LNG  to  generate  power 
for  processes  (lighting,  drying, 
sorting  etc.)  and 
for  moving 
equipment  (tractors,  harvesters, 
graders etc.) 

industrial 
commercial 

  Off-grid 
customers, 
customers, 
large 
sizeable  gas  distribution  systems 
that  can  use  LNG  to  feed  their 
systems  (regasification  of  LNG  is 
required) 

  Old  distribution  systems  (‘virtual’ 
gas pipeline using LNG instead of 
investing 
replacement  gas 
pipelines) 

in 

  Remote  gas  production  fields  not 
connected to the gas network 

  Peak 

shaving 

plant 
(combining  liquefaction,  storage 
and regasification)  

LNG 

In  the  case  of  gas-to-gas  competition,  there  are  several  options  with  which  LNG  may  be 
introduced to a country. The common feature of all options is that regasified LNG is eventually 
supplied to grid-connected customers. One option is that LNG sourced from a terminal situated 

2 The list of LNG market development options included in the Table is not exhaustive. Other options, such 
as the use of LNG as engine fuel for municipal vehicles, were not identified during field visits, and thus were 
not analysed further in this Study. 

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in another country is regasified and transported via pipeline for final consumption to the Eastern 
Partner  country  concerned.  Another  option  is  for  an  LNG  receiving  terminal  to  be  built  in  the 
Eastern Partner country, and regasified LNG from this terminal to supply customers connected to 
the  gas  network.    Alternatively,  LNG  from  in-country  or  outside  country  terminal  can  be 
transported  via  trucks  or  rail  to  grid  connected  customers  (LNG  needs  to  be  regasified  at  the 
consumption end). Finally, there is also the possibility of having swaps (pipeline gas for LNG), in 
case it is feasible (contractually, economically) for an Eastern Partner country with no sea access 
to purchase LNG for physical delivery to a terminal in another country, and another party to off-
take this LNG in exchange for piped gas that is physically delivered to the Eastern Partner country 
concerned.   

Under  Gas-to-gas  competition,  LNG  derived  gas  should  be  competitive  in  price  against  piped 
natural gas to induce end-users to purchase.  However, even in case regasified LNG is not price 
competitive against natural gas, LNG could be viable in case there are security of supply benefits 
for  the  society  and  economy,  arising  from  the  diversification  of  supply  source/route  potential 
provided by LNG supplies. Such benefits are particular to each Eastern Partner country. Cost-
benefit analysis is undertaken to monetise such benefits and assess whether they outweigh costs, 
for  those  Eastern  Partner  countries  where  gas-to-gas  competition  options  are  shown  to  be 
applicable.  

In the case of gas-to-other fuels competition, the LNG development options are dependent on 
the uses of LNG.  For the purpose of this study, we do not review exhaustively all potential uses 
of LNG (direct fuel) but focus on a number of key LNG uses.  LNG can be used directly as a fuel 
by  trucks,  or  by  ships  or  by  agricultural  and  mining  customers  who  can  use  LNG  as  fuel  for 
processes (e.g. drying etc.) or heavy equipment (tractors, graders etc.).  The common feature in 
these uses is the need to deliver LNG to the filling stations or to the customer’s storage facility. 
Alternatively,  regasified  LNG  can  be  used  by  different  types  of  off-grid  customers  (industrial, 
commercial, remote towns etc.). These customers could potentially use LNG for various needs 
(heating,  turbines,  furnaces  etc)  and  for  supplying  their  customers  (distribution  systems).  The 
distinguishing feature for these uses is that LNG is not used directly as fuel but is regasified and 
the derived gas is used in internal installations. In these cases, customers are required to have 
regasification facilities. Additionally, gas from remote gas production fields not connected to the 
gas  network  can  be  liquefied  and  LNG  can  be  transported  to  end-customers  by  trucks  e.g.  to 
filling stations.   

Not all gas-to-other fuels competition options are applicable to all Eastern Partner countries.  The 
use of LNG to fuel long haul trucks or ships would necessitate the country to be a hub for regional 
transport or to have sea access or developed waterways; supply of LNG by trucks to customers 
not connected to the gas network, would require the existence of sizeable off-grid customers in 
adequate numbers and a transport infrastructure that allows trucks to reach customers.  Supply 
options for LNG also differ between countries.  For example, establishing  an LNG terminal will 
not be possible for countries that lack sea access. Not all countries have rail networks that can 
allow transportation of LNG.  In some cases, there could be virtually no possibilities for receiving 
LNG via pipelines that are outside the control of involved stakeholders.   

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Price competitiveness of LNG against other compering fuels is a key precondition for the viability 
of Gas-to-other fuels competition options.  Another precondition is that the size of the market for 
the end-use should be sufficiently large to justify the investments needed in the chain of supplying 
LNG to the target end-users (e.g. investments in trucks, filling stations, regasification plants etc.).   

The benefits of substituting current fuels with LNG to economy and society are the energy cost 
reduction and the environmental emission reductions associated with substitution by LNG of more 
polluting  fuels3.  The  above  benefits  are  particular  to  each  use  and  each  country  and  can  be 
monetized.  

2.2  Analysis of applicable options for LNG market development 
per country  
2.2.1 Analysis of supply modalities  
The designated supply chain within each Eastern Partner country and for each of the applicable 
LNG market  development  options  within  that country,  are defined.   Routes and  infrastructures 
(existing and planned) are identified.   

2.2.2 Estimation of costs involved in the supply options 
For  each  of  the  applicable  LNG  market  development  options,  the  costs  involved  in  the  supply 
route are estimated.  In case of established modalities (e.g. cross-border charges, transit charges, 
transportation of LNG by existing fleets of trucks or by existing rail-block trains etc.) relevant unit 
costs  are  assessed.    In  case  of  new  infrastructures  (e.g.  building  of  a  new  LNG  terminal,  a 
liquefaction  facility,  a  regasification  facility,  a  storage facility  etc),  capex,  opex  (which  together 
with assumptions on depreciation, rates of return and throughout volumes, determine the relevant 
unit costs) are estimated.  For options that involve retrofitting of engines (e.g. for the use of LNG 
as fuel for trucks), relevant costs are assessed.   

The cost assumptions used in the analysis are based on international benchmarks for similar (to 
the  extent  possible)  infrastructure,  and/or  assumptions  based  on  the  Consultant’s  estimates. 
These costs can be taken as a proxy to actual costs, to perform a high-level assessment of the 
potential  viability  of  the  options,  and  would  need  to  be  verified  or  changed  following  detailed 
studies and quotes from manufacturers/suppliers.   

2.2.3 Assessment of price competitiveness of supply options 
This  is  an  important  part  of  the  analysis,  involving  the  assessment  of  the  expected  price 
competitiveness of LNG vis-a-vis natural gas (for the options under the gas-to-gas competition 
category),  and  vis-à-vis  for  other  competing  fuels  (under  the  gas-to-other  fuels  competition 

3  Gas-to-other  fuels  competition  has  limited  impact  on  security  of  energy  supply,  as  competing  fuels  are  either 
indigenous (e.g. firewood) or may supplied from large number of suppliers in competitive markets (e.g. oil products) 

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category). This analysis shows which options are economically viable, and which are not.  The 
assessment of price competitiveness of each supply option was done using ‘Netback Analysis’.  

Netback analysis provides an answer to the question: What should the LNG price be at the source 
(terminal) so that, when all the costs of transporting and transforming the LNG to reach the target 
end consumer are added, the price of LNG to the final customer is competitive compared to the 
price paid for existing fuels?  Netback analysis starts from the price that the end-customer pays 
for  a  fuel,  and  goes  backward  subtracting  all  costs  involved  in  the  LNG  supply  option  under 
examination up to the source of LNG, in order to determine what should be the price of LNG at 
the source in order for the particular option to be competitive.  In case the price that LNG should 
have at the source is lower than the ‘market’ price of LNG at the source (the current regional spot 
price), then the option is not economically viable, and vice versa.  The LNG price at the source, 
which is derived from the netback analysis, is effectively the maximum price that can be paid for 
LNG, so that when all costs to reach the end-customer are added, the final price for LNG can be 
competitive against fuel prices at the end-customer level. This analysis differs for each Eastern 
Partner country, even for the same type of option, as competing fuels have different prices at the 
end-customer level and supply costs are often different for each country.   

Under  gas-to-gas  competition,  netback  analysis  shows  the  price  that  LNG  should  have  at  the 
source so that the regasified  LNG  can compete at the  end-customer  level  with current  natural 
gas.  Under  gas-to-other  fuels  competition,  netback  analysis  shows  the  price  that  LNG  should 
have  at  the  source  so  that  LNG  can  compete  at  the  end-customer  level  with  other  fuels  (e.g. 
diesel, heating oil, LFO/HFO etc.), thus leading to substitution of such fuels by LNG.   

The netback analysis has been carried out on a high-level, i.e. using proxy of actual costs based 
on  international  benchmarks  and  assumptions.  All  calculations  have  been  made  using  current 
data concentring market prices, consumption levels and LNG supply costs. Sensitivity analysis 
has been used to assess the robustness of the results in fluctuations of key parameters. 

The detailed approaches to conducting Netback Analysis, relating to each applicable LNG Market 
development option in each Eastern Partner country, are provided in Annexes 2 and 3. 

2.3 Detailing and prioritization of specific actions  
2.3.1 Cost-Benefit Analysis (CBA) 
2.3.1.1 Methodology 

CBA indicates whether an LNG market development option has benefits to economy and society 
that outweigh its costs.  The methodology that we followed for CBA is in accordance with the EC 
CBA Guide for infrastructure investments4.  

4 DG Regio (2015) EC CBA Guide for infrastructure investments, available at: 
https://ec.europa.eu/regional_policy/sources/docgener/studies/pdf/cba_guide.pdf  

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2.3.1.2 Benefits under Gas-to-gas competition 

CBA is carried out for all applicable gas-to-gas competition LNG market development options in 
each Eastern Partner country.  LNG market development options under gas-to-gas competition 
can have both gas reduction costs benefits to the country’s economy (in case LNG is shown to 
be  price  competitive  to  existing  gas  supplies)  and  security  of  supply  benefits  (through 
diversification of supply source or route). Therefore, although the analysis under the Section 2.2 
may  show  that  an  option  is  not  viable,  a  CBA  is  undertaken  to  assess  whether  its  assessed 
economic benefits outweigh the costs associated with introducing the option in the country and 
the price increase of using more expensive LNG in a country’s economy.  

2.3.1.3 Benefits under Gas-to-other fuels competition 

CBA  was  carried  out  for  those  applicable  gas-to-other  fuels  competition  LNG  options  in  each 
Eastern Partner country that are assessed to be viable. Only in case of a viable option, LNG can 
displace  more  expensive fuels  and result  in  benefits  from  a reduction  in  the  energy  bill  of  the 
economy.    Moreover,  the  substitution  of  fuels  that  are  associated  with  higher  greenhouse  gas 
emissions, by gas, can bring about additional environmental benefits.    

2.3.1.4 Monetisation of economic benefits linked to price competitiveness  

Monetisation  of  the  economic  benefits  linked  to  price  competitiveness  under  each  applicable 
option, requires an assessment of the market size for LNG that could be developed under the 
particular option.  The assessed market size, combined with the estimated incremental decrease 
in the unit cost of gas under gas-to-gas competition, (or the decrease in the unit cost of energy 
under gas-to-other fuels  competition)  estimated on  the  basis  of netback analysis,  provides  the 
monetised estimate of the price competitiveness benefits.      

2.3.1.5  Market sizing for LNG development options  

The approach to assess potential LNG market size for options being appraised is qualitative and 
differs by LNG option. The approach involves, inter alia, assessing volumes of gas that could be 
open to competition, any capacity limitations on interconnections, loading capacity for trucks at 
the source LNG terminal, and other considerations, for each Eastern Partner country. Particularly 
when assessing the impact of LNG receiving terminals, and given that no gas market simulation 
was carried out within the frame of this Study, the impact of combinations of LNG supply prices 
and terminal utilization were examined, to provide a range of potential results. 

2.3.1.6 Monetising Security of supply benefits 

Monetising  security  of  supply  benefits  entails  an  assessment  of  how  the  introduction  of  an 
additional source (LNG) in the Eastern Partner country mitigates the impact of an exogenous gas 
disruption to the Eastern Partner country (e.g. a cut-off in gas supplies from an existing gas supply 
source).  Estimating  the  security  of  supply  would  require  calculating  four  key  elements:  the 
probability  of  such  a  disruption  taking  place,  the  days  of  disruption,  the  incremental  gas 
consumption that can be covered by LNG in the case of a disruption, and the value of disrupted 
gas to the Eastern Partner country’s economy.   

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2.3.1.7 Monetising Environmental benefits 

Monetising the environmental impact of an option that involves substitution of other fuels by LNG, 
involves  an  estimation  of  the  decrease  in  greenhouse  gas  emissions  that  LNG/gas  produces 
compared to the other fuels that it displaces. This is based on the following steps:  

1.  Estimating the GHG emissions factors (tonnes of CO2 per unit) for LNG/natural gas and 

for each of the fuels substituted 

2.  Estimating the GHG emissions saved (tonnes of CO2) for the volumes of fuels that were 

substituted by LNG (according to the previously discussed market size) 

3.  Monetising  the  GHG  emissions  saved  in  accordance  with  a  shadow  price  (long  term 
opportunity cost) of GHG emissions (based on the assumptions of ENTSOG in the 2018 
TYNDP Scenario Report) 

It  is  noted  that  for  the  purpose  of  the  high-level  analysis  performed  in  this  Study,  the  GHG 
emissions  saving  is  based  on  a  benchmark  aggregate  value  of  GHG  emissions  for  LNG  and 
diesel5. The actual impact of the competing fuels depends on factors such as the type and age of 
the trucks (e.g. a fleet of old trucks with Euro-4 engines would have a different carbon footprint 
than a renewed fleet Euro-6 engines), and their service modality (distance travelled in urban and 
rural areas/motorways)6. To ascertain the actual impact of switching to LNG in each country, the 
conditions  in the country’s  transport  sector (type and age  of  truck  engines,  service modalities, 
regulatory limitations) would have to be further analysed. 

2.3.1.8 Quantitative indicators  

In addition to the monetised CBA, we have included an assessment of the expected impact of 
LNG supplies to the market, using capacity-based indicators in line with ENTSOG, to the extent 
permissible (e.g. N-1 Indicator, Import Route Diversification, Demand Curtailment). 

2.3.2 Assessment of prerequisites and key success factors 
For each option that is deemed to be viable, we identify prerequisites and key success factors for 
its implementation. Prerequisites include the necessary agreements in place to enable an option 
to be realised, for example, the Turkey-Ukraine agreement for passing of LNG ships through the 
Bosporus Straits, or availability of Caspian gas for the supply of gas to be liquefied and exported 
to  other  countries.  Prerequisites  also  include  the  legal  and  regulatory  framework  that  enables 
each  viable  LNG  market  development  option  to  be  implemented,  and  the  development  of 
upstream  or  downstream  infrastructure.  For  example,  the  existence  of  technical  standards  for 
construction and operation of filling stations, or the existence of road safety standards for trucks, 
or the existence of small-scale liquefaction facilities. Other prerequisites relate to the removal of 
obstacles to cost reflectiveness, e.g. subsidisation of diesel or other fuels that causes difficulties 

5 Source: I. Smajla et al. (Energies Journal),” Fuel Switch to LNG in Heavy Truck Traffic”, 2019 
6 See for example the results of LNG to diesel comparison of TNO, Emissions testing of a Euro VI LNG-diesel dual fuel 
truck in the Netherlands, April 2019, for specific types of engines and routes. 

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or  even  impossible  for  LNG  to  compete,  and  the  establishment  of  a  level  plain field  regarding 
inter-fuel  competition.  Prerequisites  can  also  be  of  a  regional  nature,  requiring  inter-country 
cooperation e.g. availability of a network of filling stations across several countries, so that LNG-
fuelled trucks can operate across major international transport routes.   

Key success factors relate to factors that could be conducive to, incentivise and accelerate LNG 
market  development,  for  the  options  deemed  to  be  viable,  in  the  Eastern  Partner  countries 
concerned.  These success factors include financial incentives (grants, subsidies, tax breaks) for 
investors and users in the viable LNG market options.   

2.3.3 Priorities and policy directions 
For Eastern Partner countries with more than one potentially viable options, a time prioritization 
is  proposed  (short-term,  medium-term,  longer-term),  on  the  basis  of  qualitative  assessment  of 
factors that include the number and controllability of prerequisites for implementation of the option 
and the complexity and time involved for its development. Policy directions are also proposed for 
the  development  of  the  options,  taking  into  account,  where  relevant,  policy  directions  as 
expressed by stakeholders during country missions and workshops. 

2.3.4 Proposed actions 
Proposals on specific actions to be undertaken by the Eastern Partner countries, to evaluate and 
prepare for the commencement of the LNG market development options, are formulated for each 
Eastern  Partner  country.  Regional  cooperation  actions,  where  applicable,  are  included  in  the 
recommendations. The potential timing of the actions is identified, as immediate (can start without 
constraints), short-term (1-3 years), medium-term (3-5 years) and long-term (over 5 years). 

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3  LNG Market Prospects in Armenia 

3.1 Identification of applicable LNG market development options 
An overview of the Armenian gas sector is provided in Annex 1.1. Following the analysis of the 
gas market information, and discussions with stakeholders during the field visit to the country, the 
key findings related to the development of LNG markets in Armenia are as follows: 

  Gas-to-gas competition from LNG seems to be a non-applicable, or at best a very weak 
case, for Armenia.  This is due to lack of proximity to LNG sources, from which LNG 
can be transported to the country at reasonable cost.   

  Also,  Gazprom  Armenia  is  the  owner  of  the  transmission  system  (operated  by  its 
subsidiary Transgaz LLC) and has a monopoly on gas imports for wholesale and retail 
supply (2 bcm/yr supplies from Gazprom Russia).  An additional 0.5 bcm/yr of gas is 
imported from Iran, but this is a special tolling agreement that involves the gas used to 
produce electricity, which is then exported back to Iran. 

  LNG  could  be  considered  for  security  of  supply  purposes  (i.e.  import  LNG,  regasify 
and store it for emergency use) but this is an expensive option compared to others e.g. 
storing natural gas in existing UGS facilities at Abovyan. 

  On the other hand, Armenia appears to have potential for use of LNG as road transport 
fuel.  Armenia has a sizable fleet of trucks involved in local, regional and international 
transport (over 65,500 trucks), the majority  of which (65%)  are fuelled  by petrol  and 
secondarily by diesel (34%). This fleet includes a number of long haul trucks that are 
involved in the  transport of goods regionally or internationally  (e.g. from Armenia to 
Georgia,  Russia  and  Europe)  over  distances  exceeding  1,500  kms  per  journey,  and 
provided a sufficient number of these  trucks can be induced to switch to LNG, there 
could be a potential market.  

  Notably, Armenia has one of the largest networks in the region of CNG filling stations.   

There  are  380  CNG  filling  stations  in  the  country,  with  CNG  sales  amounting  to  0.6 
bcm annually.  85% of passenger vehicles are fuelled by CNG, the rest by diesel. Most 
CNG filling stations are quite old and need of modernization, and could be converted 
to use LNG as well (L-CNG).   

  The familiarity of consumers with using CNG, the existence of  filling stations and the 
availability  of  technology  for  their  conversion  to  use  LNG,  provide  advantages  to 
developing a market for LNG for trucks, provided LNG is competitive in price to diesel.    

  LNG can be supplied by establishing a small scale liquefaction facility to convert piped 
gas into LNG; Gazprom Armenia is interested in invest in such a facility, provided there 
is a potential market for LNG for use in transport, and private investment takes place 
in required supporting infrastructure (transporting LNG to filling stations, filling stations, 
storage etc.). An alternative option is to source LNG through Georgia (e.g. Black Sea 
LNG receiving terminal or liquefaction terminal with truck loading facility, provided that 

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such infrastructure is developed in Georgia) which is then transported by truck/rail to 
Armenia, or to source LNG by trucks from Russia. 

  Use of LNG virtual pipelines to supply off-grid consumers or distribution systems is not 
an applicable option for Armenia, as around 95% of the country is already gasified. 

Based on the above analysis, the only applicable LNG market development option for Armenia is 
the use of LNG as engine fuel for long-haul trucks. LNG can be sourced either from an in-country 
mini  liquefaction  facility  connected  to  the  transmission  system,  or  from  Georgia,  in  case  LNG 
facilities (receiving or liquefaction terminal) are developed there. It is noted that development of 
an LNG receiving terminal in Georgia can only be possible in case with agreement with Turkey is 
concluded for the passing of LNG vessels through the Bosporus Straits. 

3.2 Assessment of viability of applicable LNG market options 
3.2.1 Use of LNG as engine fuel for trucks 
This LNG market development option can be considered as potentially viable for Armenia in case 
the LNG price at the filling station is competitive to that of diesel, taking into consideration the 
efficiency gains of LNG engines, as well as all costs associated with the LNG supply chain.  

The  available  information  on  Armenia’s  traffic  of  long-haul  trucks  (local  and  transit)  is  not 
sufficiently detailed to allow reasonable assumptions to estimate the market size of LNG as fuel 
for trucks. For this reason, instead of performing netback analysis to estimate the maximum price 
of  LNG to be competitive  to diesel,  we  estimate  the  LNG  market  size (number  of  LNG-fuelled 
trucks and annual LNG volumes consumed) required for prices of LNG and diesel to be on par, 
under different scenarios of LNG/natural gas prices at the beginning of the supply chain. 

The potential LNG supply sources examined for Armenia include an LNG receiving terminal and 
a liquefaction terminal in Georgia and an in-country mini liquefaction facility. For each source, a 
base price and positive/negative sensitivities, as displayed in Table 2, have been assessed.   

Table 2: Examined prices of LNG/natural gas at the source for Armenia 

Terminal 

Georgia LNG receiving terminal7 
Georgia liquefaction terminal8 
In-country mini liquefaction facility9 

Assumed price at terminal (EUR/1000m3) 

Base price 
220 
222 
183 

+25% 
275 
277 
229 

+50% 
330 
333 
275 

-15% 
187 
189 
155 

-25% 
165 
166 
137 

The analysis has been carried out for long-haul trucks retrofitted to use LNG, traveling 91,000 km 
per annum. The costs for development of a new filling station for LNG is considered (development 
of a new L-CNG station or upgrade of an existing CNG station would result in lower costs). The 

7 The price for LNG in Black Sea is assumed to be the price at the Greek Revythoussa terminal (210 EUR/1000m 3, 
source: DG Energy, “Gas Market Report Q2 2019”), with an uplift of 5% to reflect additional transportation cost and 
crossing through the Bosporus straits. 
8 Equal to the gas price in the Georgian market (Source: GEOSTAT) 
9 Gas price for large end users, including transmission cost (PSRC, “Tariffs for natural gas supply to consumers”) 

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competing price of diesel has been assumed to be at the current market level, of 0.64 EUR/lt10. 
The detailed approach and calculations are presented in Annex 3.1. It is noted that cases in which 
the  minimum  LNG  market  size  is  estimated  to  require  over  1,000  LNG-fuelled  trucks  are  not 
further analysed, as a high penetration of LNG trucks, not corresponding to the EU experience11, 
would be required.   

Figure 2 presents the minimum number of LNG-fired trucks that have to operate in Armenia, and 
the minimum LNG volumes to be supplied annually, for the market to be developed, in case the 
base price applies at the LNG source.  

Figure  2:  Minimum  number  of  LNG-fired  trucks  for  market  development  in  Armenia  and 
corresponding annual LNG market size, under base price12 

(a) Minimum number of LNG-fired trucks 

(b) Minimum LNG market size 

The minimum number of LNG-fired trucks in the case of Armenia, for all price scenarios and LNG 
supply variants are presented in Figure 3. 

Figure 3: Minimum number of LNG-fired trucks in Armenia for all price sensitivities13 

10 Source: Maxoil website (accessed 1/11/2019) 
11 Current EU fleet of 6,000 LNG-fired trucks (NGVA, “NGVA Europe marks the 200th European LNG fuelling station 
with a revamp of its stations map”, May 2019) amounts to less than 1% of the total fleet of 6.5 million heavy duty trucks 
(Source: LNG Blue Corridor, “Feasibility study about the SoNor Corridor”, May 2018)  
12 N/A denotes market size requiring over 1,000 LNG-fuelled trucks 
13 Values exceeding 1,000 LNG-fired trucks are not presented. 

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The results of the analysis show that, in case LNG is sourced from a receiving terminal in Georgia 
at  the  base  price,  LNG  can  be  competitive to  diesel  provided  at  least  around  130  LNG  trucks 
operate in the Armenian market; this number of trucks can be lower provided the source price is 
below the assumed base price. However, for this supply modality to be applied, an agreement 
with Turkey for the passing of LNG vessels through the Bosporus Straits must be concluded, as 
a prerequisite for the potential development of an LNG terminal in Georgia. Supply from a mini 
liquefaction terminal, which is the most expensive solution, would require around 340 LNG-fuelled 
trucks to be competitive. 

Considering that Armenia has a sizable fleet of trucks involved in local, regional and international 
transport, it appears that a market for LNG in road transport could potentially develop, in case the 
LNG prices remain at the assumed base price or less. Consequently, use of LNG as engine fuel 
for trucks can be considered as a potentially viable option for Armenia. The sourcing of LNG from 
a  possible  LNG  receiving  terminal  in  Georgia  (assuming  first  the  securing  of  agreement  with 
Turkey for the Bosporus Straits and secondly the financial/economic viability of such a terminal), 
would render enhanced possibilities for developing an LNG engine fuel market in Armenia, as the 
minimum required number of trucks to render the option viable is 140, as opposed to more than 
double the number of trucks in case in-country liquefaction is applied. It is noted that in order to 
better size the size of the market, and its attractiveness, analysis of detailed data on the operation 
of  long-haul  trucks  (such  as  number  of  local  and  transit  trucks,  destinations  and  distances 
covered) in Armenia would be required.   

Economic analysis was performed for the identified minimum required LNG market, to estimate 
the extent to which economic benefits for using LNG as engine fuel (energy cost reduction for end 
consumers, impact on GHG emissions) outweigh the costs for developing the option. The analysis 
shows that the reduction of GHG emissions has a positive impact (Figure 4).  

Figure 4: Present value of economic costs and benefits for use of LNG as engine fuel for trucks in 
Armenia 

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3.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
3.3.1 Use of LNG as engine fuel for trucks 
Table 3 below describes the key prerequisites for effective implementation of the option of using 
LNG  as  engine  fuel  for  trucks  in  Armenia.  The  prerequisites  concern  the  appropriate  price 
differential between LNG and diesel to ensure viability, as well as the necessary changes in the 
legal  and  regulatory  framework,  or  introduction  of  new  legislation  and  regulations,  including 
permits  and  licenses.  The  legal  and  regulatory  prerequisites  relate  not  only  to  import  and 
operation of trucks, but extend to the supply chain for LNG concerning trucks: filling stations, truck 
loading facilities at LNG terminal in Georgia, in case this option is implemented in the neighbouring 
country and LNG is sourced from there, in-country liquefaction plants and truck loading facilities 
at these plants, in case LNG is sourced from piped gas in the country. The interest of sufficient 
truck  owners  to  switch  to  LNG,  and  the  attraction  of  investments  to  develop  the  necessary 
infrastructure  (filling  stations,  liquefaction  facilities)  is  also  critical  for  the  development  of  the 
market. 

It is noted that the prerequisites related to the import of LNG and the development of relevant 
import facilities in Georgia are listed separately in Section 6.3.1. 

Table 3: Prerequisites for development of LNG as engine fuel for trucks 

Prerequisite 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 

1 

Sufficient price 
differential between 
LNG and diesel (as 
discussed in Section 
3.2.1)  

Critical – on/off 
condition, as switching 
to LNG requires an 
attractive price of LNG 
vis-à-vis diesel at the 
end use 

2 

Interest of a critical 
mass of truck owners to 
switch to LNG 

Viability of the option is 
dependent on having a 
minimum market size 
to justify investments. 
This size is smaller 

Armenia is 
responsible for 
avoiding subsidies 
that distort price 
differential. LNG and 
diesel source prices 
are determined in 
accordance with 
international demand 
and supply 
conditions (except in 
the case where LNG 
is sourced from an 
in-country 
liquefaction facility, 
in which the price is 
determined by gas 
import contracts)   
Decision of truck 
owners 

Uncertain 

Medium 

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Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

Legal & Regulatory 

1  Regulations and 
standards for the 
design, manufacturing 
and installation of the 
LNG fueled trucks and 
different components 
(e.g. pressure control 
regulator, LNG filling 
receptacle etc.) for 
approval of LNG 
vehicles import and 
operation14, 15 
2  Road regulations for 

circulation of LNG 
fuelled vehicles 

3 

LNG and L-CNG filling 
stations permits and 
licences, notably   
building license, 
operation license, and 
business license16 

(and more attainable) 
in case a supply chain 
from a prospective 
LNG receiving terminal 
in Georgia is 
established.  

Need to ensure safety, 
efficiency, quality and 
environmental 
protection. There are 
various European and 
international standards 
that could be 
incorporated in 
national legislation as 
the basis for granting 
approval. 

Need to ensure safety, 
by stipulating any 
restrictions in 
movement e.g. in 
cases of heavy traffic, 
adverse weather 
conditions affecting 
visibility and road 
conditions etc.  
Need to ensure the 
eligibility of the 
selected site for the 
station, compliance 
with operational 
obligations (e.g. 
opening hours, station 
throughput, safety 
obligations, and 
business registration of 
the entity.  The 
licenses require testing 
and acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  

14 DG MOVE, LNG Blue Corridors, Vehicle Regulations - State of the Art, December 2013 
15 DG MOVE, LNG Blue Corridors, LNG stations Regulations -State of the art, December 2013 
16 DG MOVE, LNG Blue Corridors, Guidelines for set up & operation of stations, May 2015 

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4 

LNG and L-CNG filling 
stations regulatory 
guidelines16 in relation 
to set-up and 
construction (e.g. 
distance, tank levels 
etc.), operation (e.g. 
guarantee sufficient 
product), and 
maintenance (planned 
maintenance work in a 
programmed schedule) 
of the station. 

5  Road safety regulations 
for trucks carrying LNG 
to the filling stations.   

6  Regulations governing 

TPA of LNG carrying 
trucks at LNG terminal 
in Georgia (in case this 
supply variant is used) 

7  Regulations governing 

loading of LNG to trucks 
at LNG terminal in 
Georgia (in case this 
supply variant is used) 

8  Regulations governing 
pricing of LNG terminal 
truck loading facilities in 
Georgia (in case this 
supply variant is used, 
and there is price 
regulation for third party 

Need to ensure safety 
and efficiency of the 
station.  The 
regulations require 
testing and acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  

LNG transportation 
carries some potential 
hazards, linked to 
flammability as well as 
the impact of cryogenic 
fuel exposure or 
leakage.  There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR17).   
Need to ensure 
transparent and non-
discriminatory access 
of truck operators to 
the truck loading 
facilities 
Need to establish rules 
and procedures for 
how truck operators 
will use the truck 
loading facilities, 
including LNG truck 
approval procedure, 
LNG specifications, 
procedures for 
determining the LNG 
mass loaded etc.  
Need to have 
published tariffs for 
truck loading facility 
services at the 
terminal, that are non-
discriminatory for 
users, and regulations 

Under the sole 
control of Armenia 

Low 

Low 

Under the control of 
Armenia (for 
Armenian road 
network) and 
Georgia (for 
Georgian road 
network) 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

17 Acronym for “Accord européen relatif au transport international des marchandises Dangereuses par Route” i.e. the 
European Agreement concerning the International Carriage of Dangerous Goods by Road 

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9 

access to such 
facilities) 
Permits and licenses, 
including technical 
specifications, for truck 
loading facilities at LNG 
terminal in Georgia (in 
case this supply variant 
is used) 

10  Permits and licences, 

including technical 
specifications, for 
liquefaction facilities (in 
case LNG is sourced 
from the gas network 
and loaded on to trucks)  

11  Permitting process, 
including technical 
specifications, for truck 
loading at liquefaction 
facility (in case there is 
a liquefaction facility)  

12 

(Amendment to) law to 
specify whether/which 
type of liquefaction 
facilities are regulated 
(TPA and pricing) 
13  Regulations governing 
TPA of LNG trucks at 
liquefaction facility (in 
case there is a 
regulated liquefaction 
facility) 

14  Regulations governing 

pricing of liquefaction 
facility (in case there is 
a regulated liquefaction 
facility) 

for the allowed costs in 
such tariffs 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, to 
address safety issues 
including fire 
protection. 
Need to have permits 
and regulations for site 
requirements, health 
and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, to 
address safety issues 
including fire 
protection. 

Need to establish rules 
and procedures for 
how truck operators 
will use the truck 
loading facilities, 
including LNG truck 
approval procedure, 
LNG specifications, 
procedures for 
determining the LNG 
mass loaded etc. 
Need to have 
published tariffs for 
use of the liquefaction 
plant services, that are 
non-discriminatory for 
users, and regulations 
for the allowed costs in 
such tariffs 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

Under the sole 
control of Armenia 

Low 

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Infrastructure 

1 

Interest of investors to 
implement necessary 
infrastructure (filling 
stations, in-country 
liquefaction facility) 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled trucks 
to be able to operate  

Decision of investors  Medium 

Table 4 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for trucks. These factors influence the speed of market development. Some of the key 
success factors relate to the State providing support to catalyze investments in LNG trucks and 
filling  stations,  including  retrofitting  of  CNG  stations  to  L-CNG,  which  are  widespread  in  the 
country. Others relate to having a regulatory framework that favors ‘cleaner’ LNG use in trucking 
and punishes more ‘dirty fuels’.  State can also regulate the level of subsidies in other fuels, to 
make LNG more competitive. Other factors relate to the role of State and State organizations to 
foster  changes  and  to  support  investors  (one-stop-shop).  Finally,  the  role  of  information 
campaigns for consumers, users and investors, is important to overcome resistance to change 
and to boost interest. 

Table 4: Key success factors for development of LNG as engine fuel for trucks 

Key success factors 

Rationale 

1  An LNG receiving terminal, with truck loading 

facilities, is established by Georgia 

This would significantly lower the costs 
involved in the LNG supply chain, and thus 
make the critical mass of trucks required for 
the option to be viable more attainable 

2  Conducive fiscal framework (low taxes, low import 
duties, availability of state grants and rebates) for 
the purchase of LNG fuelled trucks or the 
retrofitting of existing trucks to LNG.  

3  Setting and enforcing circulation restrictions for 
trucks that use older generation engines with 
higher emissions detrimental to the environment 
(e.g. Euro 4 fuels)  

4  Reduction of subsidies and favourite tax treatment 

of fuels competing with LNG, to make LNG more 
competitive and incentivise its use. 

5  Conducive fiscal framework (specific concession 

regimes, tax holidays, state grants18) conducive to 
investment in construction of new LNG filling 
stations, or for retrofitting petrol stations to include 
LNG, or for retrofitting CNG stations to offer also 
LNG (L-CNG). Also, state co-funding of LNG R&D 
activities 

6  Awareness and promotion campaigns for LNG. 

Having sufficient network of LNG stations is a 
major success factor. Incentivising private 
investment is one way to develop the market.   

Consumers should be educated as to the 
potential features and benefits of LNG in 
transport.  Investors should be informed on 
the opportunities available.  Such campaigns 
can counter resistance to change and speed 
up interest. 

18 ‘Connecting Europe Facility’, for example, provides grant to co-finance investment in LNG filling stations in the EU 

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7  Having a ‘National champion’ e.g. the Ministry of 

Territorial Administration and Infrastructure and/or 
a State Committee that includes gas company 
and other key stakeholders.  The role of the 
National champion would be to coordinate the set-
up of the required legal and regulatory framework, 
develop and implement policy and incentives, to 
remove obstacles in for LNG market development 
and to act as one-stop-shop for investors. Its role 
would also include planning the number and 
location of LNG filling stations and facilities 
(possibly introducing limited concessions for 
infrastructure) so as to avoid stranded 
investments.    

Many initiatives are slowed down by 
regulatory gaps or unclear legislation, lack of 
implementing administrative mechanisms 
and bureaucracy and lack of action.  Such 
problems are exacerbated due to lack of 
awareness and resistance to change or 
inertia.  For example, customs may not be 
familiar with rules and regulations for the new 
LNG vehicles and delay their clearance.   

3.4 Priorities and policy directions 
The single potentially viable option for LNG market development identified for Armenia is the use 
of LNG as engine fuel for trucks.  

This option could be viable using an in-country mini liquefaction facility, but the high investment 
costs in required infrastructure necessitate a large number of LNG fueled trucks for viability. On 
the other hand, supplies from a potential LNG terminal in Georgia, in case implemented, could 
considerably reduce costs, but this infrastructure is subject to an external decision (by Georgia) 
and dependent on a number of factors controlled by third, external, parties. 

Decision  for  and  implementation  of  an  in-country  LNG  supply  chain  using  a  mini  liquefaction 
facility could be done in short-term horizon, as it only involves local actors. In contrast, supplies 
of LNG from a receiving terminal in Georgia would involve a longer-term horizon due to the nature 
of the investment, and the uncertainties surrounding the decisions of the involved external parties.  

Given  the  benefits  of  reducing  energy  costs  and  GHG  emissions,  this  option  merits  further 
investigation, to assess in detail its feasibility, and decide on the potential policies to be adopted, 
favoring the use of LNG. These policies could encompass, at the minimum, having a legal and 
regulatory framework conducive to the development of an LNG supply chain, and could expand 
to cover incentives for the use of LNG. 

3.5 Proposed preparatory actions 
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the option of using LNG as engine fuel for trucks.  

Table 5: Proposed preparatory actions for the option of LNG-fueled trucks in Armenia 

Proposed Actions 

Timing 

Initial / Preparatory Actions 
1  Perform a feasibility study for use of LNG as engine fuel in 
Armenia (covering not only greenfield projects, but also 
retrofitting of existing CNG stations to L-CNG) 

Immediate 

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2  Develop a national policy framework for the use of LNG in 

trucks, deciding on the role that the State wishes to undertake 

Implementation Actions 
3  Prepare the regulatory and legal framework (legal 

4 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the LNG supply chain 
In case the State undertakes a proactive role in developing 
infrastructure, prepare the incentive mechanisms to attract 
investments 

5  Conduct awareness raising campaigns to attract end-users 

and investors’ interest 

Short-term / After the study is 
concluded (in case it is positive 
and Armenia decides to pursue) 

Short-term (based on national 
policy framework) 

Short-term (based on national 
policy framework) 

Short-term (based on national 
policy framework) 

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4  LNG Market Prospects in Azerbaijan 

4.1 Identification of applicable LNG market development options 
An overview of the Azeri gas sector is provided in Annex 1.2. Following the analysis of the gas 
market information, and discussions with stakeholders during the field visit to the country, the key 
findings related to the development of LNG markets in Azerbaijan are as follows: 

  Gas-to-gas  competition  from  LNG  is  not  applicable  in  Azerbaijan.  This  is  due  to  the 
country being a major gas producer and exporter, but also due to lack of proximity to 
LNG sources from which LNG can be transported to the country at reasonable cost.  
There are discussions for establishing an LNG terminal in the Azeri part of the Black 
Sea  to  receive  LNG  from  Kazahkstan,  but  this  will  basically  involve  Azerbaijan  as  a 
transit country as Kazakh LNG will be regasified and exported to other markets.   

  Another potential option, that could involve LNG in gas-to-gas competition but in other 
countries,  is  the  export  of  Azeri  gas  to  a  liquefaction  terminal  in  Georgia,  and  the 
resulting  LNG  shipped  to  markets  such  as  Ukraine,  Moldova  and  Romania  where  it 
competes  against  piped  gas  supplies.  Currently,  all  gas  production  in  Azerbaijan 
available  for  export  has  already  been  contracted.  However,  new  fields  under 
development  could  potentially  supply  an  export  route  to  a  liquefaction  terminal  in 
Georgia over the mid-term. The liquefaction terminal in Georgia could also be supplied 
with gas from Kazakhstan and Turkmenistan, in case an LNG receiving terminal is built 
at the Azeri Caspian Sea coast.  

  Gas-to-other  fuels  competition  from  LNG  is  an  applicable  option  in  Azerbaijan  for 
supply of off-grid areas. Although around 95% of the Azeri territory is already gasified, 
Government roadmap targets 100% gasification.  Development of LNG virtual pipelines 
is  one  of  the  options  being  assessed  as  a  means  for  supplying  off-grid  areas  that 
currently consume other fuels.   

  Gas-to-other  fuels  competition  from  LNG  in  the  transport  sector  could  also  be  an 
applicable  option  in  Azerbaijan.  Although  transport fuels  (e.g.  diesel)  are  subsidised 
and  development  of  a  supply  chain  to  supply  LNG  as  fuel  for  trucks  would  not  be 
economically  viable,  given  the  environmental  benefits  of  LNG  use  in  transport,  the 
Government is willing to consider supporting use of LNG in this respect.  Azerbaijan 
has also the largest fleet active in the Caspian Sea, a new port in Baku is operational, 
and a new shipyard has been developed by SOCAR. Development of LNG as fuel for 
ships is of interest to Government, especially for environmental reasons. 

  No prospects seem to exist for the use of LNG in agriculture or mining , as demand is 
limited, and potential consumers are already connected to the transmission system.  

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Based on the above analysis, the applicable LNG market development options for Azerbaijan, all 
of  which  concern  gas-to-other  fuels  competition,  are  presented  in  Table  6.  The  only  potential 
source of LNG supply is an in-country mini liquefaction facility connected to the Azeri transmission 
system. 

Table 6: Applicable options for LNG market development in Azerbaijan 

Options for LNG market development 

Sources of supply 

Gas-to-Other Fuels 
Competition 

LNG as engine fuel for long-haul trucks 
LNG as engine fuel for ships operating in the Caspian 
Sea 
LNG supplies to the remaining off-grid areas in 
Azerbaijan, to increase gasification 

In-country mini 
liquefaction facility 

4.2 Assessment of viability of applicable LNG market options 
4.2.1 Use of LNG as engine fuel for trucks 
This LNG market development option can be considered as potentially viable for Azerbaijan in 
case the LNG price at the filling station is competitive to that of diesel, taking into consideration 
the efficiency gains of LNG engines, as well as all costs associated with the LNG supply chain.  

However, due to the very low current diesel price in Azerbaijan (0.26 EUR/lt19), LNG cannot be 
competitive. The results of the calculations show that the required LNG price at the filling station 
(285.4 EUR/1000 m3), after having taken into consideration fuel efficiency gains, is lower than the 
required switching costs (296 EUR/1000 m3), which include recovery of retrofitting costs and a 
small price reduction as incentive to the truck owner. The detailed approach and calculations are 
presented in Annex 3.1. 

Consequently,  use  of  LNG  as  engine  fuel  for  trucks  does  not  seem  to  be  a  viable  option  for 
Azerbaijan.  Nevertheless,  the  Azeri  Government  have  indicated  that  it  intends  to  explore  this 
option further for environmental reasons and potentially provide support. 

4.2.2 Use of LNG as engine fuel for ships 
The  use  of  LNG  by  the  existing  fleet  of  ships  operating  in the  Caspian  Sea,  in  case  emission 
control rules are applied by Azerbaijan (such as reduction of sulphur emissions) would have to 
compete with other options, such as the use of scrubbers or low sulphur fuel oil. Internationally, 
for  ships  currently  operating  in  the  sea  areas  outside  Emission  Control  Areas  (ECAs),  the 
switching to LNG has not been the preferred option, as the retrofitting cost has been considered 
higher than that of alternative solutions20. The use of LNG can be more attractive in the case of 
new builds, provided that the price differential between LNG and the existing bunkering fuels is 

19 Source: Azpetrol website (accessed 1/11/2019) 
20 See analysis in Oxford Institute for Energy Studies, “LNG Supply Chains and the Development of LNG as a Shipping 
Fuel in Northern Europe”, 2019 

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sufficient to cover the additional cost of an LNG-fuelled ship, and that bunkering of LNG is possible 
at least in the Baku port.    

The attractiveness of this LNG option differs for each individual case of ship, as it depends on a 
number of factors, including the vessel’s size and type, age, service area, fuel used, refuelling 
pattern,  prices  of  competing  fuels,  etc.  For  this  reason,  a  case-by-case  analysis  would  be 
required, to examine for which ships use of LNG would be competitive.  

Data  on  the  Azerbaijan  shipping  sector,  required  to  perform  a  contextualized  analysis  of  this 
option, were not available. To facilitate further analysis of this option, in this Study we provide an 
indicative example, concerning a new build 50,000 MT PANAMAX type vessel operating in the 
Black Sea, with LNG and MGO as competing fuels and bunkering at an LNG terminal in Ukraine. 
The detailed approach and calculations are described in Annex 3.4. The rationale and approach 
followed in this example could be used as a basis to assess the use of LNG as engine fuel in 
Azerbaijan.  

4.2.3 Supply of LNG to off-grid distribution systems 
This LNG market development option can be considered as potentially viable for Azerbaijan  in 
case the natural gas price supplied to the end customers at the targeted areas for gasification is 
competitive to that of the competing fuels, taking into consideration the efficiency gains of natural 
gas, as all costs associated with the LNG/natural gas supply chain. 

Data on the areas of Azerbaijan to be gasified, required to perform a contextualized analysis of 
this option, were not available. The rationale and approach followed in the case study analysing 
this LNG market development option for Georgia (Annex 3.2) can be used as a basis to assess 
the financial viability of supplying LNG to ungasified regions of Azerbaijan.  

4.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
4.3.1 Use of LNG as engine fuel for trucks 
Table 7 describes the key prerequisites for effective implementation of the option of using LNG 
as engine fuel for trucks in Azerbaijan. The prerequisites concern the appropriate price differential 
between LNG and diesel to ensure viability, as well as the necessary changes in the legal and 
regulatory  framework,  or  introduction  of  new  legislation  and regulations,  including  permits  and 
licenses.  The  prerequisites  relate  not  only  to  import  and  operation  of  trucks  but  extend  to  the 
supply  chain  for  LNG  concerning  trucks:  filling  stations,  liquefaction  plants  and  truck  loading 
facilities at these plants. The interest of sufficient truck owners to switch to LNG, and the attraction 
of  investments  to  develop  the  necessary  infrastructure  (filling  stations,  liquefaction  facilities)  is 
also critical for the development of the market. 

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Table 7: Prerequisites for development of LNG as engine fuel for trucks 

Prerequisite 

Rationale 

Market 
1  LNG end use price 

should be subsidized, to 
compete against diesel 
or subsidies on diesel 
lifted (current price 
differential does not 
allow development of 
this option, as discussed 
in Section 4.2.1)    
Interest of a critical mass 
of truck owners to switch 
to LNG 

2 

Legal & Regulatory 
1  Regulations and 

standards for the design, 
manufacturing and 
installation of the LNG 
fueled trucks and 
different components 
(e.g. pressure control 
regulator, LNG filling 
receptacle etc.) for 
approval of LNG 
vehicles import and 
operation21, 22 

2  Road regulations for 
circulation of LNG 
fuelled vehicles 

3  LNG and L-CNG filling 
stations permits and 
licences, notably   
building license, 
operation license, and 
business license23 

Critical – on/off 
condition, as 
switching to LNG 
requires an attractive 
price of LNG vis-à-vis 
diesel at the end use 

Viability of the option 
is dependent on 
having a minimum 
market size to justify 
investments  

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.  There are 
various European 
and international 
standards that could 
be incorporated in 
national legislation as 
the basis for granting 
approval. 
Need to ensure 
safety, by stipulating 
any restrictions in 
movement e.g. in 
cases of heavy traffic, 
adverse weather 
conditions affecting 
visibility and road 
conditions etc.  
Need to ensure the 
eligibility of the 
selected site for the 
station, compliance 
with operational 
obligations (e.g. 
opening hours, 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Under the sole 
control of Azerbaijan 

Low 

Decision of truck 
owners 

Medium 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

21 DG MOVE, LNG Blue Corridors, Vehicle Regulations - State of the Art, December 2013 
22 DG MOVE, LNG Blue Corridors, LNG stations Regulations -State of the art, December 2013 
23 DG MOVE, LNG Blue Corridors, Guidelines for set up & operation of stations, May 2015 

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station throughput, 
safety obligations, 
and business 
registration of the 
entity.  The licenses 
require testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  
Need to ensure 
safety and efficiency 
of the station.  The 
regulations require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  
LNG transportation 
carries some 
potential hazards, 
linked to flammability 
as well as the impact 
of cryogenic fuel 
exposure or 
leakage. There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR.   
Need to have permits 
and regulations for 
site requirements, 
health and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 
Need to have permits 
and regulations 
specifying layout 

4  LNG and L-CNG filling 
stations regulatory 
guidelines23 in relation to 
set-up and construction 
(e.g. distance, tank 
levels etc.), operation 
(e.g. guarantee sufficient 
product), and 
maintenance (planned 
maintenance work in a 
programmed schedule) 
of the station. 

5  Road safety regulations 
for trucks carrying LNG 
to the filling stations.   

6  Permits and licences, 
including technical 
specifications, for 
liquefaction facilities  

7  Permitting process, 
including technical 
specifications, for truck 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

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loading at liquefaction 
facility  

requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 

8 

(Amendment to) law to 
specify whether/which 
type of liquefaction 
facilities are regulated 
(TPA and pricing) 
9  Regulations governing 
TPA of LNG trucks at 
liquefaction facility  

10  Regulations governing 

pricing of liquefaction 
facility  

Infrastructure 
1 

Interest of investors to 
implement necessary 
infrastructure (filling 
stations, in-country 
liquefaction facility) 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc. 
Need to have 
published tariffs for 
use of the 
liquefaction plant 
services, that are 
non-discriminatory for 
users, and 
regulations for the 
allowed costs in such 
tariffs 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
trucks to be able to 
operate  

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

Under the sole 
control of Azerbaijan 

Low 

Decision of investors  Medium 

Table 8 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for trucks. These factors influence the speed of market development.  Some of the 
key success factors relate to the State providing support to catalyze investments in LNG trucks 
and filling stations.  Others relate to having a regulatory framework that favors ‘cleaner’ LNG use 
in trucking and punishes more ‘dirty fuels’.  State can also regulate the level of subsidies in other 
fuels,  to  make  LNG  more  competitive.  Other  factors  relate  to  the  role  of  State  and  State 
organizations  to  foster  changes  and  to  support  investors  (one-stop-shop).  Finally,  the  role  of 
information campaigns for consumers, users and investors is important to overcome resistance 
to change and to boost interest. 

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Table 8: Key success factors for development of LNG as engine fuel for trucks 

Key success factors 

Rationale 

1  Conducive fiscal framework (low taxes, low import 
duties, availability of state grants and rebates) for 
the purchase of LNG fuelled trucks or the 
retrofitting of existing trucks to LNG.  

2  Setting and enforcing circulation restrictions for 
trucks that use older generation engines with 
higher emissions detrimental to the environment 
(e.g. Euro 4 fuels)  

3  Conducive fiscal framework (specific concession 

regimes, tax holidays, state grants24) conducive to 
investment in construction of new LNG filling 
stations, or for retrofitting petrol stations to include 
LNG, or for retrofitting CNG stations to offer also 
LNG (L-CNG). Also, state co-funding of LNG R&D 
activities 

4  Awareness and promotion campaigns for LNG. 

5  Having a ‘National champion’ e.g. the Ministry of 

Energy or a State Committee that includes gas 
company and other key stakeholders.  The role of 
the National champion would be to coordinate the 
set-up of the required legal and regulatory 
framework, develop and implement policy and 
incentives, to remove obstacles in for LNG market 
development and to act as one-stop-shop for 
investors. Its role would also include planning the 
number and location of LNG filling stations and 
facilities (possibly introducing limited concessions 
for infrastructure) so as to avoid stranded 
investments.    

Having sufficient network of LNG stations is a 
major success factor. Incentivising private 
investment is one way to develop the market.   

Consumers should be educated as to the 
potential features and benefits of LNG in 
transport.  Investors should be informed on 
the opportunities available.  Such campaigns 
can counter resistance to change and speed 
up interest. 
Many initiatives are slowed down by 
regulatory gaps or unclear legislation, lack of 
implementing administrative mechanisms 
and bureaucracy and lack of action.  Such 
problems are exacerbated due to lack of 
awareness and resistance to change or 
inertia.  For example, customs may not be 
familiar with rules and regulations for the new 
LNG vehicles and delay their clearance.   

4.3.2 Use of LNG as engine fuel for ships 
Table 9 describes the key prerequisites for effective implementation of the option of using LNG 
as  engine  fuel  for  ships  in  Azerbaijan.  The  prerequisites  concern  appropriate  price  differential 
between  LNG  and  fuel  oil  to  ensure  viability,  and  the  introduction  of  necessary  regulations 
concerning  LNG  ships  design  and  operation,  as  well  as  regulations  and  permits  concerning 
bunkering facilities. The choice of ship owners to use LNG as fuel and the development of required 
infrastructure in the Baku port is also critical for the development of the market. 

24 ‘Connecting Europe Facility’, for example, provides grant to co-finance investment in LNG filling stations in the EU 

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Table 9: Prerequisites for development of LNG as engine fuel for ships25 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and fuel oil (as 
discussed in Section 
4.2.2), for the vessels 
that are targeted for fuel 
switching  

2 

Interest of ship owners 
to retrofit or build new 
LNG-fueled vessels, 
based on technical 
feasibility and financial 
attractiveness 
Legal & Regulatory 
1  Codes and Regulations 
for the design of LNG 
ships, based on 
guidelines set by 
organisations such as 
the International 
Maritime Organisation 
(IMO), the Society of 
International Gas 
Tankers 
and Terminal Operators 
(SIGTTO), the Oil 
Companies International 
Marine Forum (OCIMF) 
and other ISO, 
European (EN) and 
National Fire Protection 
Association (NFPA) 
standards 

2  Codes and Regulations 
for the design and 
operation of LNG 
bunkering facilities, 
based on ISO guidelines 
(for systems and 
installations for supply of 
LNG as fuel to ships) as 
well as other 
international guidelines  

Viability of the option 
is dependent on LNG 
being competitive to 
fuel oil for use in 
shipping, so that 
investments in fuel 
conversion for the 
particular vessels can 
be recovered 
There are alternative 
options to be applied 
by ship owners to 
reduce costs and 
emissions 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Under the sole control 
of Azerbaijan (fuels 
produced and 
marketed locally) 

Low 

Decision of ship 
owners 

Medium to high 

Under the sole control 
of Azerbaijan 

Low 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Under the sole control 
of Azerbaijan 

Low 

25 In case of LNG supplied from liquefaction facilities to ports via trucks, the relevant points of Table 8 also apply. 

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3  LNG bunkering facilities 
permits and licences  

Infrastructure 
1 

Implementation of 
necessary infrastructure 
(LNG bunkering 
infrastructure at Baku 
port) 

Need to ensure the 
suitability of the 
selected site for the 
facility, compliance 
with operational 
obligations (e.g. 
opening hours, station 
throughput, safety 
obligations) etc. The 
licenses require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
vessels to be able to 
operate  

Under the sole control 
of Azerbaijan 

Low 

Decision of State 
and/or private 
investors 

Medium 

Table 10 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for ships. These factors influence the speed of market development.  Some of the key 
success factors concern IMO regulations that influence the choice of LNG driven ships, especially 
new builds, vis-à-vis ships using other low emission fuels. Other prerequisites relate to having a 
legal  framework  conducive  to  investments  and  access  to  finance  for  the  large  investments 
needed.  Another  prerequisite  for  LNG  fueled  ships  is  the  availability  of  adequate  bunkering 
infrastructure. 

Table 10: Key success factors for development of LNG as engine fuel for ships 

Key success factors 

Rationale 

2. 

1.  Reliability,  operating  costs  advantages  (driving 
from  low  LNG  price  and  fuel  efficiency)  and 
environmental advantages of LNG fuelled ships 
are  maintained  over  the  long  term,  so  as  to 
justify large investment in LNG ships   
Stricter  IMO  regulations  on  carbon  emissions, 
and government enforcement, favouring the use 
of LNG in ships   
IMO regulations not to include greenhouse gas 
emissions (methane) where LNG is seen to be 
at a disadvantage compared to other fuels 
Availability  of  finance  (loans,  grants  etc.)  for 
investment in LNG ships.   

3. 

4. 

Access to finance is key.  Investment costs for 
for  shipping 
new  ships  are  significant 
companies, whereas retrofits are also costly, as 
larger  fuel  tanks  are  required  to  be  placed  in 
ship.   

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5. 
Availability of adequate bunkering infrastructure 
6.  National legislation conducive to investments in 

ships and/or bunkering infrastructure 

4.4 Priorities and policy directions 
Given  that  the  option  of  using  LNG  as  truck  fuels  is  not  viable  on  account  of  lack  of 
competitiveness of LNG vis-à-vis diesel, but it does have environmental benefits, the Government 
should  assess  whether  it  should  place  priority  on  developing  this  option  on  the  basis  of 
environmental policy. In doing so, the Government should undertake initiatives to improve LNG 
relative price competitiveness vis-à-vis competing fuels.  

LNG  use  for  supplying  gas  to  off-grid  remote  areas,  is  an  option  that  the  Government  could 
potentially apply to implement its national gasification strategy. In this case, the LNG supply chain 
costs would have to be compared against alternatives (CNG, piped gas) on a case-by-case basis.  

The  option  of  LNG  use  for  ships  could  be  explored  further  on  the  basis  of  the  Government’s 
environmental policy. In this respect, a case-by-case analysis of LNG application in different ship 
types operating in the Caspian Sea needs to be undertaken to ascertain feasibility, benefits and 
the ensuing priorities. 

In  case  the  Government  decides  to  move  ahead  with  the  development  of  LNG  options  for 
environmental reasons, it should decide on the timing for each option. The option of using LNG 
for supplying gas to off-grid areas could be considered as a priority, on the basis of the ease and 
speed of implementation, as the supply chain can be developed by the State, without third parties 
involved. The development of LNG as engine fuel for trucks is a second priority, as it involved 
decision by truck owners to retrofit as well as development of LNG filling stations. The option of 
introducing LNG in the shipping sector could be developed over a longer-term horizon, as it would 
require involvement and large investments from ship owners for a diverse number of vessels.  

4.5 Proposed actions  
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the identified applicable LNG market development options.  

Table 11: Proposed preparatory actions for developing the identified LNG options in Azerbaijan 

Initial / Preparatory Actions 
1  Perform feasibility studies for the use of LNG as engine fuel for 

Immediate 

Proposed Actions 

Timing 

trucks and ships, and for supply of off-grid areas. 
The studies should examine scenarios for either subsidizing 
LNG use or removal of cross-subsidies of other fuels, and 
relevant affordability studies. 

2  Develop a national policy framework for the use of LNG in road 
and water transport, deciding on the role that the State wishes 
to undertake 

Short-term / After the studies for 
the transport sector are 
concluded (in case Azerbaijan 
decides to pursue) 

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3  Develop a programme for gasification of remote areas using 

LNG supplies  

Implementation Actions 
4  Prepare the regulatory and legal framework (legal 

5 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the LNG supply chain 
In case the State undertakes a proactive role in developing 
infrastructure, prepare the incentive mechanisms to attract 
investments 

6  Conduct awareness raising campaigns to attract end-users 

and investors’ interest 

7  Undertake initiatives to catalyze interest and seek joint 

commitments of stakeholders (Socar, Baku port, ship owners) 
to develop the use of LNG in shipping 

Short-term / After the relevant 
study is concluded (in case 
Azerbaijan decides to pursue) 

Short-term / based on national 
policy framework and 
gasification programme 
Short-term / based on national 
policy framework and 
gasification programme 
Short-term / based on national 
policy framework and 
gasification programme 
Short to medium-term / based 
on national policy framework 

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5  LNG Market Prospects in Belarus 

5.1 Identification of applicable LNG market development options  
An overview of the Belarusian gas sector is provided in Annex 1.3. Following the analysis of the 
gas market information, and discussions with stakeholders during the field visit to the country, the 
key findings related to the development of LNG markets in Belarus are as follows: 

  Gas-to-gas competition from LNG is not applicable in Belarus.  Imports of gasified LNG 
through pipeline from Klaipeda and/or Świnoujście LNG terminals is an option that can 
only  be  applicable  in  case  Belarus  considers  technical  reverse  flow  of  existing 
interconnections  (Poland,  Lithuania)  and/or  new  interconnections.  According  to  the 
stakeholders, no new interconnections are currently planned, and it is not feasible to 
make technical changes to the system to introduce reverse flow from Lithuania and/or 
Poland.  Moreover,  several  gas  interconnections  between  Belarus  and  Ukraine  are 
either decommissioned and/or unutilized.  Importing LNG from EU, using trucks and/or 
trains  and  regasifying  it  to  supply  existing  gas  network  customers,  is  technically 
feasible  but  there  is  no  apparent  demand.    According  to  Beltopgaz,  all  major  gas 
consumers  are  connected  to  either  the  distribution  or  the  transmission  system  and 
these  are  not  considered  as  potential  customers  for  LNG,  in  competition  with  piped 
gas.   

  Gas-to-other fuels competition from LNG could be applicable in Belarus for road and 
waterways transport.  Belarus Government policy is to favour electricity use, given that 
they expect cheap electricity to be produced from their Nuclear Power Plant planned 
to be commissioned soon, and concurrently the use of electricity in transport (road, rail 
and water) is of priority for the country, compared to development of other alternatives, 
such  as  LNG.  On  the  other  hand,  Belarus  is  home  to  manufacturers  of  trucks  and 
heavy  work  vehicles  (MAZ,  BELAZ),  which  have  already  launched  pilot  projects  for 
LNG  fuelled  vehicles.  The  country  has  a  sizeable  fleet  of  local  and  imported 
international  long  haulage  trucks  (over  12,000  in  2013),  as  well  as  diesel  heavy 
tractors,  that  could  be  potentially  converted  to  use  LNG  as  fuel.  Gazprom  Transgas 
Belarus is considering a small-scale liquefaction facility primarily for supplying LNG to 
filling stations.  

  LNG as fuel for ships operating in Belarusian waterways could also be an applicable 
option, as the country has a number of waterways where passenger and cargo ships 
operate.  The  Belarus  Ministry  of  Transport  and  Communications  is  interested  to 
assess this option. It is noted that the use of LNG in vessels would compete with other 
technologies,  such  as  the  use  of  electric  propulsion  systems  and  electric  powered 
ships for Belorussian waterways, which is being examined by the Ministry of Transport 
and Communications (a relevant study was initiated in 2018).   

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  No significant prospects seem to exist in gas-to-other fuels competition for the supply 
of  remote/off-grid  customers.    Gasification  is  high  across  the  country;  almost  all 
consumers are gasified apart from households. CNG is extensively used in agricultural 
sector, where 50% of users are connected to the grid, and the national strategy is to 
promote biomass and peat for energy use. 

Based  on  the  above  analysis,  the  applicable  LNG  market  development  options  for  Belarus 
concern the use of LNG as engine fuel in trucks, and potentially in waterways (Table 12). Potential 
sources  of  LNG  supply  can  either  be  the  EU  LNG  terminals  close  to  Belarus  (Świnoujście, 
Klaipeda) or development of an in-country mini liquefaction facility connected to the Belarusian 
transmission system. 

Table 12: Applicable options for LNG market development in Belarus 

Options for LNG market development 

Sources of supply 

Gas-to-Other Fuels 
Competition 

LNG as engine fuel for long-haul trucks 

LNG as engine fuel for vessels in Belarusian 
waterways 

  Truck loading in Świnoujście 
and/or Klaipeda terminals 

  In-country mini liquefaction 

facility 

5.2 Assessment of viability of applicable LNG market options 
5.2.1 Use of LNG as engine fuel for trucks 
This LNG market development option can be considered as potentially viable for Belarus in case 
the LNG price at the filling station is competitive to that of diesel, taking into consideration the 
efficiency gains of LNG engines, as well as all costs associated with the LNG supply chain.  

The  available  information  on  the  traffic  of  long-haul  trucks  (local  and  transit)  in  Belarus  is  not 
sufficiently detailed to allow reasonable assumptions to estimate the market size of LNG as fuel 
for trucks.  For this  reason,  instead  of  performing a  netback  analysis  to  estimate the maximum 
price of LNG to be competitive to diesel, we estimate the LNG market size (number of LNG-fuelled 
trucks and annual LNG volumes consumed) required for prices of LNG and diesel to be on par, 
under different scenarios of LNG/natural gas prices at the beginning of the supply chain. 

The potential LNG supply sources examined for Belarus include the LNG terminals in Świnoujście 
and  Klaipeda,  and  an  in-country  mini  liquefaction  facility.  For  each  source,  a  base  price  and 
positive/negative sensitivities, as displayed in Table 13, have been assessed.   

Table 13: Examined prices of LNG/natural gas at the source for Belarus 

Terminal 

Świnoujście LNG terminal26 
Klaipeda LNG terminal27 

Assumed price at terminal (EUR/1000m3) 

Base price 
200 
200 

+25% 
250 
250 

+50% 
300 
300 

-15% 
170 
170 

-25% 
150 
150 

26 As information is not available, the same price as Klaipeda is used 
27 Source: DG Energy, “Gas Market Report Q2 2019” 

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In-country mini liquefaction facility28 

234 

293 

351 

200 

175 

The analysis has been carried out for long-haul trucks retrofitted to use LNG, traveling 91,000 km 
per annum. The costs for development of a new filling station for LNG is considered (development 
of a new L-CNG station or upgrade of an existing CNG station would result in lower costs). The 
competing price of diesel has been assumed to be at the current market level, of 0.59 EUR/lt29. 
The detailed approach and calculations are presented in Annex 3.1. It is noted that cases in which 
the  minimum  LNG  market  size  is  estimated  to  require  over  1,000  LNG-fuelled  trucks  are  not 
further analysed.   

Figure 5 presents the minimum number of LNG-fired trucks that have to operate in Belarus, and 
the minimum LNG volumes to be supplied annually, for the market to be developed, in case the 
base price applies at the LNG source.  

Figure  5:  Minimum  number  of  LNG-fired  trucks  for  market  development  in  Belarus  and 
corresponding annual LNG market size, under base price30 

(a) Minimum number of LNG-fired trucks 

(b) Minimum LNG market size 

The minimum number of LNG-fired trucks for the Belarusian case, for all price scenarios and LNG 
supply variants are presented in Figure 6. 

28 Gas price  for large end users, including transmission cost (Source:  input provided from the Ministry of Energy of 
Belarus) 
29 Source: Input provided from the Ministry of Energy of Belarus 
30 N/A denotes market size requiring over 1,000 LNG-fuelled trucks 

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Figure 6: Minimum number of LNG-fired trucks in Belarus for all price sensitivities31 

The results of the analysis show that for supply prices higher that the current ones, the use of 
LNG in road transport, under the examined assumptions, are non-viable. At the base price, LNG 
supplies from Klaipeda terminal (the closest one to Belarus) can be competitive to diesel, in case 
more than 200 LNG-fuelled trucks refuel in Belarus, while with a market of similar size supplies 
from the Świnoujście terminal could also be attractive in case LNG prices decrease. Use of a mini 
liquefaction terminal would require a considerably larger market, together with a decrease of LNG 
prices. 

Considering  that  Belarus  has  a  sizeable  fleet  of  local  and  imported  international  long  haulage 
trucks (over 12,000 in 2013), and local manufacturing of LNG-fueled trucks could lower switching 
costs, it seems that market for LNG in road transport could potentially develop, in case the LNG 
prices remain  at the  assumed  base  price  or  less.  Consequently,  using  LNG  as  engine fuel for 
trucks can be considered as a potentially viable option for Belarus. It is noted that in order to better 
size the size of the market, and its attractiveness, analysis of detailed data on the operation of 
long-haul trucks (such as number of local and transit trucks, destinations and distances covered) 
in Belarus would be required.   

Economic analysis was performed for the identified minimum required LNG market, to estimate 
the extent to which economic benefits for using LNG as engine fuel (energy cost reduction for end 
consumers, impact on GHG emissions) outweigh the costs for developing the option. The analysis 
shows that the reduction of GHG emissions has a positive impact (Figure 7).  

31 Values exceeding 1,000 LNG-fired trucks are not presented. 

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Figure 7: Present value of economic costs and benefits for use of LNG as engine fuel for trucks in 
Belarus 

5.2.2 Use of LNG as engine fuel for ships 
The  Belarusian  inland  fleet  comprises  small  vessels  (one  self-propelled  barge,  147  pushed 
barges with an average capacity of 769 metric tons and 72 push and tow boats32).  

The use of LNG as fuel for such small vessels is challenging, even  in case LNG price can be 
lower  than  the  existing bunkering fuels,  as the  large LNG fuel  tanks take up  storage  capacity, 
affecting the ship’s productivity and freight earnings. Thus, the application potential for smaller 
newbuilds running on LNG is limited, while retrofit of vessels in operation is not suitable for all 
types of small vessels, and its cost can be higher than that of a newbuild33. 

Push boats and barges that are predominant in Belarus cannot be adapted to LNG, because they 
do  not  have  room  to  place  an  LNG  tank.  The  use  of  LNG  in  newbuilds  for  the  Belarusian 
waterways, or potentially retrofitting of existing vessels should be examined on a case-by-case 
basis, as it depends on financial (cost for retrofitting, LNG price) and technical factors (tank space, 
safety issues). It is also noted that LNG would compete with other potential new options, such as 
the use of electric propulsion systems and electric powered ships for Belorussian waterways, (a 
relevant study was initiated by the Ministry of Transport and Communications in 2018).  

32 Source: Draft of the White Paper on efficient and sustainable inland water transport in Europe, revised – 10 October 
2009  -  Working  Party  on  Inland  Water  Transport  -  Working  Party  on  the  Standardization  of  Technical  and  Safety 
Requirements in Inland Navigation (SC.3/WP.3) 
33 Source:  L.  Simmer  et  Al  (Journal  of  Clean  Energy  Technologies),  “Liquefied  Natural  Gas  as  a  Fuel  in  Inland 
Navigation: Barriers to Be Overcome on Rhine-Main-Danube”, July 2016 

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5.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
5.3.1 Use of LNG as engine fuel for trucks 
Table 14 describes the key prerequisites for effective implementation of the option of using LNG 
as engine fuel for trucks in Belarus. The prerequisites concern the appropriate price differential 
between LNG and diesel to ensure viability, as well as the necessary changes in the legal and 
regulatory  framework,  or  introduction  of  new  legislation  and regulations,  including  permits  and 
licenses.  The prerequisites relate not only to import and operation of trucks.  For example (under 
prerequisite  #5  below),  there  is  already  a  Belarusian  Regulation  on  Safety  Transportation  of 
Dangerous Cargos by Road Transport (No 61 of 2010). LNG is included in this regulation and 
classified in accordance with UN codes.  Other prerequisites relate to the supply chain for LNG 
concerning trucks: filling stations, liquefaction plants and truck loading facilities at these plants. 
The  interest  of  sufficient  truck  owners  to  switch  to  LNG,  and  the  attraction  of  investments  to 
develop the necessary infrastructure (filling stations, liquefaction facilities) is also critical for the 
development of the market. 

Table 14: Prerequisites for development of LNG as engine fuel for trucks 

Prerequisite 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and diesel (as discussed 
in Section 5.2.1)  

Critical – on/off 
condition, as 
switching to LNG 
requires an attractive 
price of LNG vis-à-vis 
diesel at the end use 

2 

Interest of a critical mass 
of truck owners to switch 
to LNG 

Viability of the option 
is dependent on 
having a minimum 
market size to justify 
investments  

Legal & Regulatory 
1  Regulations and 

standards for the design, 
manufacturing and 

Need to ensure 
safety, efficiency, 
quality and 

Belarus is 
responsible for 
avoiding subsidies 
that distort price 
differential. LNG and 
diesel source prices 
are determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is 
sourced from an in-
country liquefaction 
facility, in which the 
price is determined 
by gas import 
contracts)   
Decision of truck 
owners 

Uncertain 

Medium 

Under the sole 
control of Belarus 

Low 

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installation of the LNG 
fueled trucks and 
different components 
(e.g. pressure control 
regulator, LNG filling 
receptacle etc.) for 
approval of LNG 
vehicles import and 
operation34, 35 

2  Road regulations for 
circulation of LNG 
fuelled vehicles 

3  LNG and L-CNG filling 
stations permits and 
licences, notably   
building license, 
operation license, and 
business license36 

4  LNG and L-CNG filling 
stations regulatory 
guidelines36 in relation to 
set-up and construction 
(e.g. distance, tank 
levels etc.), operation 
(e.g. guarantee sufficient 
product), and 
maintenance (planned 
maintenance work in a 

environmental 
protection.  There are 
various European 
and international 
standards that could 
be incorporated in 
national legislation as 
the basis for granting 
approval. 
Need to ensure 
safety, by stipulating 
any restrictions in 
movement e.g. in 
cases of heavy traffic, 
adverse weather 
conditions affecting 
visibility and road 
conditions etc.  
Need to ensure the 
eligibility of the 
selected site for the 
station, compliance 
with operational 
obligations (e.g. 
opening hours, 
station throughput, 
safety obligations, 
and business 
registration of the 
entity.  The licenses 
require testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  
Need to ensure 
safety and efficiency 
of the station.  The 
regulations require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

34 DG MOVE, LNG Blue Corridors, Vehicle Regulations - State of the Art, December 2013 
35 DG MOVE, LNG Blue Corridors, LNG stations Regulations -State of the art, December 2013 
36 DG MOVE, LNG Blue Corridors, Guidelines for set up & operation of stations, May 2015 

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programmed schedule) 
of the station. 

5  Road safety regulations 
for trucks carrying LNG 
to the filling stations.   

6  Permits and licences, 
including technical 
specifications, for 
liquefaction facilities (in 
case LNG is sourced 
from the gas network 
and loaded on to trucks)  

7  Permitting process, 
including technical 
specifications, for truck 
loading at liquefaction 
facility  (in case there is 
a liquefaction facility)  

8 

(Amendment to) law to 
specify whether/which 
type of liquefaction 
facilities are regulated 
(TPA and pricing) 
9  Regulations governing 
TPA of LNG trucks at 
liquefaction facility (in 
case there is a regulated 
liquefaction facility with 
TPA) 

10  Regulations governing 

pricing of liquefaction 

granted and after 
(inspection/checks for 
compliance)  
LNG transportation 
carries some 
potential hazards, 
linked to flammability 
as well as the impact 
of cryogenic fuel 
exposure or 
leakage.  There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR.   
Need to have permits 
and regulations for 
site requirements, 
health and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc. 
Non-discriminatory 
and published tariffs 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

Under the sole 
control of Belarus 

Low 

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facility (in case there is a 
regulated liquefaction 
facility with regulated 
pricing) 

Infrastructure 
1 

Interest of investors to 
implement necessary 
infrastructure (filling 
stations, in-country 
liquefaction facility) 

for use of the 
liquefaction plant 
services are required, 
in case of TPA to the 
facility.  Such tariffs 
ought to be 
accompanied by 
regulations for the 
costs allowed to enter 
the tariff 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
trucks to be able to 
operate  

Decision of investors  Medium 

Table 15 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for trucks. These factors influence the speed of market development. Some of the key 
success factors relate to the State providing support to catalyze investments in LNG trucks and 
filling stations. Others relate to having a regulatory framework that favors ‘cleaner’ LNG use in 
trucking and punishes more ‘dirty fuels’. State can also regulate the level of subsidies in other 
fuels, to make LNG more competitive. Other prerequisites relate to the role of State and State 
organizations  to  foster  changes  and  to  support  investors  (one-stop-shop).  Finally,  the  role  of 
information campaigns for consumers, users and investors is important to overcome resistance 
to change and to boost interest. 

Table 15: Key success factors for development of LNG as engine fuel for trucks 

Key success factors 

Rationale 

1  Conducive fiscal framework (low taxes, low import 
duties, availability of state grants and rebates) for 
the purchase of LNG fuelled trucks or the 
retrofitting of existing trucks to LNG.  

2  Setting and enforcing circulation restrictions for 
trucks that use older generation engines with 
higher emissions detrimental to the environment 
(e.g. Euro 4 fuels)  

3  Reduction of subsidies and favourite tax treatment 

of fuels competing with LNG, to make LNG more 
competitive and incentivise its use. 

4  Conducive fiscal framework (specific concession 

regimes, tax holidays, state grants37) conducive to 
investment in construction of new LNG filling 
stations, or for retrofitting petrol stations to include 
LNG, or for retrofitting CNG stations to offer also 
LNG (L-CNG). Also, state co-funding of LNG R&D 
activities 

Having sufficient network of LNG stations is a 
major success factor. Incentivising private 
investment is one way to develop the market.   

37 ‘Connecting Europe Facility’, for example, provides grant to co-finance investment in LNG filling stations in the EU 

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5  Awareness and promotion campaigns for LNG. 

6  Having a ‘National champion’ e.g. the Ministry of 

Energy or a State Committee that includes gas 
company and other key stakeholders.  The role of 
the National champion would be to coordinate the 
set-up of the required legal and regulatory 
framework, develop and implement policy and 
incentives, to remove obstacles in for LNG market 
development and to act as one-stop-shop for 
investors. Its role would also include planning the 
number and location of LNG filling stations and 
facilities (possibly introducing limited concessions 
for infrastructure) so as to avoid stranded 
investments.    

Consumers should be educated as to the 
potential features and benefits of LNG in 
transport.  Investors should be informed on 
the opportunities available.  Such campaigns 
can counter resistance to change and speed 
up interest. 
Many initiatives are slowed down by 
regulatory gaps or unclear legislation, lack of 
implementing administrative mechanisms 
and bureaucracy and lack of action.  Such 
problems are exacerbated due to lack of 
awareness and resistance to change or 
inertia.  For example, customs may not be 
familiar with rules and regulations for the new 
LNG vehicles and delay their clearance.   

5.3.2 Use of LNG as engine fuel for ships 
Table 16 describes the key prerequisites for effective implementation of the option of using LNG 
as  engine  fuel  for  inland  waterway  vessels.  The  prerequisites  concern  appropriate  price 
differential  between  LNG  and  fuel  oil  to  ensure  viability,  and  the  introduction  of  necessary 
regulations concerning LNG vessels’ design and operation, as well as regulations and permits 
concerning  bunkering  facilities.  The  choice  of  ship  owners  to  use  LNG  as  fuel  and  the 
development of required infrastructure along the waterways is also critical for the development of 
the market. 

Table 16: Prerequisites for development of LNG as engine fuel for ships38 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and fuel oil (as 
discussed in Section 
5.2.2), to justify fuel 
switching for the type of 
vessels operating in 
Belarusian waterways  

Viability of the option 
is dependent on LNG 
being competitive to 
fuel oil for use in 
shipping, so that 
investments in fuel 
conversion for the 
particular vessels can 
be recovered 

Uncertain 

LNG and fuel oil 
source prices are 
determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is sourced 
from an in-country 
liquefaction facility, in 
which the price is 
determined by gas 
import contracts)   

38 In case of LNG supplied  from liquefaction facilities  to inland ports via trucks, the relevant  points of  Table 14 also 
apply. 

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2 

Interest of ship owners 
to retrofit or build new 
LNG-fueled vessels, 
based on technical 
feasibility and financial 
attractiveness 
Legal & Regulatory 
1  Codes and Regulations 
for the design of LNG 
ships, based on the 
Environmental and 
Emissions legal 
framework related to 
European inland 
waterways, including 
UNECE Resolutions No 
21 and 61, Regulation 
(EU) 2016/1628, 
European Standard 
laying down Technical 
Requirements for Inland 
Navigation vessels 
(ESTRIN) 

2  Codes and Regulations 
for the design and 
operation of LNG 
bunkering facilities, 
based on ISO guidelines 
(for systems and 
installations for supply of 
LNG as fuel to ships) as 
well as other 
international guidelines  
3  LNG bunkering facilities 
permits and licences  

There are alternative 
options to be applied 
by ship owners to 
reduce costs and 
emissions 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Decision of ship 
owners 

Medium to high 

Under the sole control 
of Belarus 

Low 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Under the sole control 
of Belarus 

Low 

Under the sole control 
of Belarus 

Low 

Need to ensure the 
suitability of the 
selected site for the 
facility, compliance 
with operational 
obligations (e.g. 
opening hours, station 
throughput, safety 
obligations) etc. The 
licenses require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  

Infrastructure 

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1 

Implementation of 
necessary infrastructure 
(LNG bunkering 
infrastructure at inland 
ports) 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
vessels to be able to 
operate  

Decision of State 
and/or private 
investors 

Medium 

Table 17 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for vessels. These factors influence the speed of market development.  Some of the 
key success factors concern the implementation of environmental and emission requirements for 
inland waterways that can influence the choice of LNG driven ships, especially newbuilds, vis-à-
vis  ships  using  other  low  emission  fuels.  Other  key  success  factors  relate  to  having  a  legal 
framework  conducive  to  investments  and  access  to  finance  for  the  large investments  needed.  
Another factor for LNG fueled ships is the availability of adequate bunkering infrastructure.   

Table 17: Key success factors for development of LNG as engine fuel for ships 

1 

Key success factors 
Technical  constraints  (tank  sizes),  reliability, 
operating  costs  advantages  (driving  from  low 
and 
LNG 
environmental advantages of LNG fuelled ships 
are  maintained  over  the  long  term,  so  as  to 
justify large investment in LNG ships   

efficiency) 

price 

and 

fuel 

Rationale 

2  Compliance  of  Belarus  with  environmental/ 
emissions requirements for inland waterways 
3  Availability  of  finance  (loans,  grants  etc.)  for 

investment in LNG ships.   

4  Availability of adequate bunkering infrastructure 
5  National legislation conducive to investments in 

ships and/or bunkering infrastructure 

Incentive  for  the  use  of  cleaner  fuels,  such  as 
LNG 
Access  to  finance  is  key.  Investment  costs  for 
new  ships  are  significant 
for  shipping 
companies, whereas retrofits are also costly as 
larger fuel tanks are required.   

5.4 Priorities and policy directions 
The use of LNG as fuel for trucks was the only option analyzed showing, under conditions, to be 
viable.  Availability  of  LNG  in  neighboring  terminals  facilitates  the  development  of  the  required 
supply chain over a short-term horizon.  

The Government could assess feasibility in detail further and take relevant policy actions. These 
policies could encompass, at the minimum, having a legal and regulatory framework conducive 
to the development of an LNG supply chain, and could expand to cover incentives for the use of 
LNG. 

The applicability of LNG use as fuel for the ships operating in Belarus’ waterways appears to be 
limited, due to the small size and limited utilization of vessels vis-à-vis investment requirements. 
Nevertheless, in case the Government decides that this option is of interest, it should undertake 
contextualized analysis, to identify whether there are any types of vessels for which switching to 
LNG  may  be  attractive,  assessing  also  competitiveness  against  other  technologies  being 
examined by the Belarusian State (e.g. electric propulsion). 

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5.5 Proposed actions  
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the identified applicable LNG market development options.  

Table 18: Proposed preparatory actions for developing the identified LNG options in Belarus 

Initial / Preparatory Actions 
1  Perform feasibility study for the use of LNG as engine fuel for 

Immediate 

Proposed Actions 

Timing 

trucks  

2  Develop a national policy framework for the use of LNG in road 

transport, deciding on the role that the State wishes to 
undertake 

3  Perform feasibility study for the use of LNG as engine fuel for 

4 

ships 
Inclusion of the use of LNG as engine fuel for ships in the 
national policy framework 

Implementation Actions 
5  Prepare the regulatory and legal framework (legal 

6 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the LNG supply chain 
In case the State undertakes a proactive role in developing 
infrastructure, prepare the incentive mechanisms to attract 
investments 

7  Conduct awareness raising campaigns to attract end-users 

and investors’ interest 

Short-term / After the study for 
road transport is concluded (in 
case the study is positive and 
Belarus decides to pursue) 
Short-term / In case Belarus 
decides to pursue 
Short-term / After the study for 
water transport is concluded (in 
case the study is positive) 

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  

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6  LNG Market Prospects in Georgia 

6.1 Identification of applicable LNG market development options 
An overview of the Georgian gas sector is provided in Annex 1.4. Following the analysis of the 
gas market information, and discussions with stakeholders during the field visit to the country, the 
key findings related to the development of LNG markets in Georgia are as follows: 

  Gas-to-gas competition from  LNG could be applicable in Georgia.  Currently there is 
no  possibility  for  Georgia  to  receive  regasified  LNG  through  its  gas  pipeline 
interconnections with Russia,  Turkey, Armenia and Azerbaijan; only in case Georgia 
develops its own LNG receiving terminal (smaller size than the one in Ukraine), which 
the stakeholders consider as interesting to explore. This option is nevertheless heavily 
dependent  upon  Turkey  agreement  to  allow  LNG  vessels’  passage  through  the 
Bosporus Straits.   

  Georgia can facilitate gas-to-gas competition from LNG in other countries. Georgia is 
interested to establish an LNG liquefaction port terminal for exporting LNG to Ukraine, 
Moldova (via Ukraine) and further to EU markets (Romania, Hungary). This option is 
nevertheless  subject  to  availability  of  gas  to  be  liquefied  from  Azerbaijan.  Azeri 
supplies could be possible only over the mid-term, given that all current Azeri supplies 
have  been  already  contracted  and  new  fields  would  have  to  be  developed  for  this 
purpose.  Kazakhstan  and  Turkmenistan  could  also  be  a  potential  supplier  for  this 
project over the long term, in case Caspian gas is transited to Azerbaijan (through pipe 
or through an LNG receiving terminal in the Caspian Sea). 

  Swaps of piped gas for LNG landing in Turkish terminals, or terminals in SE Europe 
(Greece  and  Italy)  is  a  potential  option  for  gas-to-gas  competition,  under  certain 
conditions. This option is dependent on Turkish LNG terminals are accessible to such 
deals,  BOTAS  agreeing  to  have  such  a  swap  with  GOGC,  and  also  that  contractual 
arrangements  between  SOCAR  and  BOTAS  allow  Georgia  to  off-take  gas  from  the 
SCP.           

  Gas-to-other  fuels  competition  from  LNG  could  be  applicable  in  Georgia  for  road 
transport.  According to stakeholders, Georgia appears to have a sizable international 
long-haul traffic (export/imports and transit) that could merit the use of LNG as truck 
fuel.   

  Gas-to-other fuels competition could be also applicable to remote/off-grid customers.  
Although over 80% of gas customers are connected to the grid, LNG supply could still 
be  an  option  to  supply  selected  off-grid  consumers  and  areas  (mainly  mountainous 
towns  and  resort  areas  etc.),  within  the  frame  of  the  Government’s  aim  to  increase 
even further the country’s gasification. GOGC may be interested to establish a small-
scale liquefaction facility, to supply LNG filling stations and off-grid remote consumers. 

  Gas-to-other fuels competition does not seem applicable to sea transport, at least over 
the short to mid-term. Given that the Black Sea is not an Emission Control Area for the 

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IMO,  the  requirement  to  reduce  sulphur  emissions  from  the  current  3.5%  to  0.5% 
sulphur,  as  of  1/1/2020,  can  be  addressed  with  other  means  (scrubbers,  MGO  with 
reduced  sulphur  etc.)  instead  of  using  LNG  in  ships.  Additionally,  stakeholders 
informed us that large ships refuel in Turkish ports, as opposed to Georgian ports . 

Based on the above analysis, the applicable LNG market development options for Georgia, for 
gas-to-gas and gas-to-other fuels competition, are presented in Table 19. LNG for gas-to-other 
fuels competition can be sourced from an in-country receiving terminal, liquefaction terminal or 
mini liquefaction facility, depending on the development of the market. It is noted that development 
of an LNG receiving terminal in Georgia can only be possible in case an agreement with Turkey 
is concluded for the passing of LNG vessels through the Bosporus Straits. 

It  should  be  noted  that  gas-to-other  fuels  options  cannot  be  considered  as  drivers  for  the 
development  of  an  in-country  receiving  or  liquefaction  terminal  but  can  benefit  in  case  such 
infrastructure goes ahead. 

Table 19: Applicable options for LNG market development in Georgia 

Options for LNG market development 

Sources of supply 

Gas-to-Gas 
Competition 

Regasified LNG through the development 
of an in-country LNG receiving terminal in 
the Black Sea 
Swap of regasified LNG landing at LNG 
terminals in Turkey or SE Europe with 
piped gas supplied to Georgia through the 
SCP offtake 

Gas-to-Other 
Fuels 
Competition 

LNG as engine fuel for long-haul trucks 
LNG supplies to the remaining off-grid 
towns and consumers in Georgia, located in 
mountainous areas, to increase gasification 

Potential in-country receiving 
terminal 

LNG receiving terminals in Turkey 
(Marmara Ereglisi), Greece 
(Revythoussa, planned 
Alexadroupolis FSRU), Italy 
(Panigaglia) 

  In-country receiving terminal 

  In-country liquefaction terminal 

  In-country mini liquefaction facility 

The potential development of a liquefaction terminal in Georgia, for Caspian gas, is considered in 
the  analysis  as  an  additional  source  of  LNG  supplies  in  other  Eastern  Partners,  particularly 
Ukraine and Moldova (through Ukraine). 

6.2 Assessment of viability of applicable LNG market options 
6.2.1 Supply of regasified LNG from in-country terminal 
This LNG market development option can be considered as potentially viable for Georgia in case 
regasified LNG can arrive at a Georgian receiving terminal at a price competitive to that of the 
existing gas supply sources for the market, taking into consideration all relevant transportation 
costs.  Agreement  with  Turkey  for  passing  of  LNG  vessels  through  the  Bosporus  Straits  in  an 
on/off precondition for this option to be developed.  

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The Georgian terminal is assumed to be located in the Black Sea, near Poti. The development of 
a terminal with send-out capacity of 1 bcm/yr is assumed39, taking into consideration the size of 
the Georgian gas market. 

To estimate the competitiveness of LNG, netback analysis was performed, starting from the gas 
price in Georgia, up to the terminal, taking into consideration in-country transportation costs and 
charges  for  the  use  of  the  terminal.  The  detailed  approach  and  calculations  are  described  in 
Annex 2.2.  

The calculations are carried out using 3 scenarios of import gas prices in Georgia, so as to assess 
different  cases  of  import  price  evolution.  The  current  price  of  imported  Azeri  gas,  for  the 
commercial part of the market, amounts to 200 EUR/ 1000 m3, and has ranged from 165 – 245 
EUR/ 1000 m3 in the recent years40. However, an emerging supply gap is observed in the coming 
years,  due  to  the  expected  growth  of  demand  and  the  expiry  of  the  existing  contracts  for  the 
optional and additional gas, after 2025. In this context, the price scenarios examined correspond 
to the current level of import price plus transmission tariff (206 EUR/1000 m3), a moderate (25%) 
price increase (256 EUR/1000 m3) and a high (50%) price increase (306 EUR/1000 m3). As the 
terminal charges depend on its utilization rate, we examine cases of low (30%), medium (50%) 
and high (70%) utilization. 

Figure  8  presents  the  results  of  the  netback  analysis  for  all  examined  price  scenarios  and 
utilization rates.  

Figure  8:  Netback  analysis  results  for  supplies  of  regasified  LNG  from  in-country  terminal  in 
Georgia, all examined import prices and utilization rates 

LNG price in the Black Sea can be expected to be higher than that of the Mediterranean, due to 
the additional transport costs and fees for crossing through the Bosporus Straits. With LNG import 
price at the Greek Revythoussa terminal at 210 EUR/1000m3 in Q2 201941, it is assumed that the 
corresponding price in the Black Sea will be at least 5% higher. 

39 For a small-scale LNG receiving facility such as this, detailed analysis is required to determine which technological 
option (on-shore terminal, FRSU or FSU) is the optimum one. 
40 Source: Department of Strategic Planning and Projects of GOGC 
41 Source: DG Energy, “Gas Market Report Q2 2019” 

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The results of the netback analysis show that the financial attractiveness for development of a 
receiving  terminal  in  Georgia  depends  on  the  level  of  gas  import  prices.  Under  the  examined 
assumptions  and  market  conditions  LNG  can  be competitive for  Azeri supplies at  a  price  over 
50% of the current levels (i.e. to have an import price differential of at least 70-80 EUR/1000 m3 
between LNG  and piped  gas). This  is  of  particular  importance  after  2025,  as  the  expiry  of  the 
existing contracts for supply of optional and additional gas from the SCP can lead to an increase 
in gas supply prices.  

Economic  analysis  for  this  LNG  option  was  conducted,  to  assess  whether  the  benefits  of 
developing an LNG terminal to the economy and society can outweigh its costs, even in case the 
price of Azeri gas does not increase at appropriate levels to allow the infrastructure to be viable. 
The  analysis  covers  the  scenarios  of  the  import  prices  remaining  at  current  levels  or  facing  a 
moderate increase. The detailed approach and calculations are described in Annex 4.1. 

Figure  9  presents  the  calculated  economic  net  present  value  for  each  of  the  examined  price 
scenarios and corresponding utilization rates.  

Figure  9:  ENPV  results  for  supplies  of  regasified  LNG  from  in-country  terminal  in  Georgia,  all 
examined import prices and utilization rates 

The economic analysis results show that development of an LNG terminal in Georgia is viable in 
case LNG can be available at prices lower than those of Azeri gas, which result in both enhancing 
security of supply and reducing gas prices in the market. The use of the terminal only for security 
of supply purposes (in case LNG price exceeds that of piped gas) does not lead to positive results, 
as  the  examined  LNG  terminal  with  1  bcm/yr  capacity  can  only  partially  cover  the  demand 
curtailment that would occur in case of a supply disruption to the market (Figure 10). 

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Figure 10: Present value of economic costs and benefits of in-country terminal in Georgia 

(a) Current import price (only SoS) 

(b) 25% price increase (30% utilization) 

The impact of the LNG terminal in Georgia on the market is also highlighted by the quantitative 
indicators,  presented  in  Table  20.  The  access  to  LNG  increases  the  market  players’  ability  to 
diversify  routes,  sources  and  counterparts  of  supply,  that  are  currently  limited  to  Azeri  and 
Russian  gas.  Furthermore,  the  terminal  can  mitigate  a  potential  disruption  of  infrastructure  or 
supplies but cannot fully address it. The detailed approach and calculations of the indicators is 
provided in Annex 4.4.  

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Table 20: Quantitative indicators for in-country terminal in Georgia 

W/o terminal 

With terminal 

Impact 

N-1 indicator 

Import route 
diversification 

Demand curtailment 

61.5% 

6,236 

72% 

78.5% 

4,867 

55% 

Increase of system resilience to a 
large infrastructure disruption 
Increase of diversification of routes, 
sources and counterparts 
Reduction of curtailed demand in 
case of disruption 

Based on the above analysis, the development of an in-country LNG receiving terminal in Georgia 
can be considered as a potentially viable LNG option, in case the prices in the Georgian market 
are conducive to LNG supplies. It is noted, however, that this LNG market development option 
can  only  be  realized  in  case  an  agreement  is  concluded  with  Turkey  for  the  passage  of  LNG 
vessels through the Bosporus Straits. 

6.2.2  Swaps of piped gas with regasified LNG in Turkish or EU terminals 
The  swap  of  regasified  LNG  landing  at  a  terminal  in  Turkey,  Greece  or  Italy  with  piped  gas 
delivered  to  Georgia  through  its  offtake  of  the  SCP  would  require  an  agreement  between  the 
involved parties, to allow this virtual gas exchange. For the supply of LNG at a Turkish terminal, 
GOGC  should reach  an agreement  with  BOTAS, for  the  swap  of gas  and delivery  at the  SCP 
offtake. For the supply of LNG at the Greek or Italian terminals, a trilateral agreement would be 
required,  between  GOGC,  a  supplier  active  in  the  SE  European  markets  holding  sufficient 
volumes to perform the swap, and BOTAS, for the delivery of piped gas at the SCP offtake. 

Development of this option is conditional upon the following: 

  Price of LNG supplied at the selected terminal (including costs for use of terminal and 
entry at the transmission system) is lower than the price of gas contracted by BOTAS 
in  SCP.  In  case  the  price  of  LNG  is  higher,  the  price  differential  would  have  to  be 
covered by GOGC.  

 

Import prices of Azeri gas in the Georgian market are higher than the agreed price for 
the swap (inclusive of the cost of LNG, any price differential to be paid by GOGC, and 
service fee to be paid to the counterpart supplier). 

  The  contractual  arrangements  between  SOCAR  and  BOTAS  for  the  supply  of  gas 

through SCP allow BOTAS to deliver gas at the Georgian gas offtake. 

Following  the  recent  completion  of  the  SCP  expansion  (SCPx),  there  is  sufficient  capacity  to 
supply  the  Georgian  market.  To  perform  the  swaps,  GOGC  should  book  the  corresponding 
physical capacity at the targeted terminal. In this case, and since the exchange is virtual, there 
are no requirements for booking physical capacity along the path from the terminal to the Georgian 
market. 

The financial viability of this option cannot be assessed using benchmarks, as it depends on the 
negotiated price between GOGC and the supplier.  

The implementation of swaps would benefit the Georgian market, as it would allow access to an 
additional source of gas, without the need for developing additional infrastructure.  

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The  potential  for  swaps  should  be  further  explored,  in  particular  to  ensure  that  there  are  no 
contractual constraints for the swap, and that the price differential would create a “win-win” case 
for all involved parties.   

6.2.3 Use of LNG as engine fuel for trucks 
This LNG market development option can be considered as potentially viable for Georgia in case 
the LNG price at the filling station is competitive to that of diesel, taking into consideration the 
efficiency gains of LNG engines, as well as all costs associated with the LNG supply chain.  

The  available  information  on  the  traffic  of  long-haul  trucks  (local  and transit)  in  Georgia  is  not 
sufficiently detailed to allow reasonable assumptions to estimate the market size of LNG as fuel 
for trucks.  For this  reason,  instead  of  performing  a  netback  analysis  to  estimate the maximum 
price of LNG to be competitive to diesel, we estimate the LNG market size (number of LNG-fuelled 
trucks and annual LNG volumes consumed) required for prices of LNG and diesel to be on par, 
under different scenarios of LNG/natural gas prices at the beginning of the supply chain. 

The  potential  LNG  supply  sources  examined  for  Georgia  include  an  in-country  LNG  receiving 
terminal or liquefaction terminal and mini liquefaction facility. For each source, a base price and 
positive/negative sensitivities, as displayed in Table 21, have been assessed.   

Table 21: Examined prices of LNG/natural gas at the source for Georgia42 

Terminal 

Georgia LNG receiving terminal43 
Georgia liquefaction terminal44 

Assumed price at terminal (EUR/1000m3) 

Base price 
220 
222 

+25% 
275 
277 

+50% 
330 
333 

-15% 
187 
189 

-25% 
165 
166 

In-country mini liquefaction facility44 

222 

277 

333 

189 

166 

The analysis has been carried out for long-haul trucks retrofitted to use LNG, traveling 91,000 km 
per annum. The costs for development of a new filling station for LNG is considered (development 
of a new L-CNG station or upgrade of an existing CNG station would result in lower costs). The 
competing price of diesel has been assumed to be at the current market level, of 0.71 EUR/lt45. 
The detailed approach and calculations are presented in Annex 3.1. It is noted that cases in which 
the  minimum  LNG  market  size  is  estimated  to  require  over  1,000  LNG-fuelled  trucks  are  not 
further analysed.   

42  LNG  could  potentially  be  sourced  from  the  Revythoussa  terminal  in  Greece,  once  truck  loading  facilities  are 
developed. However, due to the large distance to Georgia (over 5,000 km round-trip), only circumstantial supplies could 
be considered, and therefore not analysed further 
43 The price for LNG in Black Sea is assumed to be the price at the Greek Revythoussa terminal (210 EUR/1000m3, 
source: DG Energy, “Gas Market Report Q2 2019”), with an uplift of 5% to reflect additional transportation cost and 
crossing through the Bosporus straits. 
44 Equal to the gas price in the Georgian market (Source: GEOSTAT) 
45 Source: SOCAR Georgia website (accessed 1/11/2019) 

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Figure 11 presents the minimum number of LNG-fired trucks that have to operate in Georgia, and 
the minimum LNG volumes to be supplied annually, for the market to be developed, in case the 
base price applies at the LNG source.  

Figure  11:  Minimum  number  of  LNG-fired  trucks  for  market  development  in  Georgia  and 
corresponding annual LNG market size, under base price 

(a) Minimum number of LNG-fired trucks 

(b) Minimum LNG market size 

The minimum number of LNG-fired trucks for the Georgian case, for all price scenarios and LNG 
supply variants are presented in Figure 12. 

Figure 12: Minimum number of LNG-fired trucks in Georgia for all price sensitivities46 

The results of the analysis show that at the base prices, use of LNG in road transport under the 
examined assumptions can be competitive to diesel with a market of 60 or 100 LNG-fired trucks, 
for supplies from an in-country receiving or liquefaction terminal, in case the preconditions for the 
establishment  of  such  terminals  are  secured.  Supplies  from  a  mini  liquefaction  facility  would 
require  a  considerably  larger  market,  at  least  around  280  trucks.  Even  in  case  LNG  prices 

46 Values exceeding 1,000 LNG-fired trucks are not presented. 

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increase, supplies from a regasification or liquefaction terminal can remain competitive to diesel 
with a market of at least 200 trucks. 

Considering that Georgia is a transit country for trade in the region, though its ports, it seems that 
a market for LNG in road transport could potentially develop, especially if the supply prices remain 
at the assumed base price or less. Consequently, use of LNG as engine fuel for trucks can be 
considered as a potentially viable option for Georgia. The sourcing of LNG from a possible LNG 
receiving terminal (assuming first the securing of agreement with Turkey for the Bosporus Straits 
and  secondly  the financial/economic  viability  of  such  a terminal)  or  a liquefaction terminal  that 
also  serves  the  Georgian  market,  would  render  enhanced  possibilities  for  developing  an  LNG 
engine fuel market in Georgia, as the minimum required number of trucks to render the option 
viable  is  60  and  100  respectively.  The  other  sourcing  option  (mini  liquefaction  facility),  would 
require fourfold number of trucks, in comparison. It is noted that in order to better size the size of 
the market, and its attractiveness, analysis of detailed data on the operation of long-haul trucks 
(such as number of local and transit trucks, destinations and distances covered) in Georgia would 
be required.   

Economic analysis was performed for the identified minimum required LNG market, to estimate 
the extent to which economic benefits for using LNG as engine fuel (energy cost reduction for end 
consumers, impact on GHG emissions) outweigh the costs for developing the option. The analysis 
shows that the reduction of GHG emissions has a positive impact (Figure 13).  

Figure 13: Present value of economic costs and benefits for use of LNG as engine fuel for trucks in 
Georgia 

6.2.4 Supply of LNG to off-grid distribution systems 
This LNG market development option can be considered as potentially viable for Georgia in case 
the natural gas price at the end customers at the areas targeted for gasification is competitive to 
that  of  firewood  (the  dominant  fuel  in  urban  areas  outside  big  cities  in  Georgia),  taking  into 
consideration the efficiency gains of natural gas, and all costs associated with the LNG/natural 
gas supply chain.  

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Annex 3.2 presents a case study for the largest off-grid town targeted for gasification. Due to the 
low price for firewood, the costs for switching from firewood to gas (including gas installation costs 
and a 20% price differential incentive) are higher (329 EUR/1000m3) than the required price of 
gas  to  be  competitive  to  firewood  (280  EUR/1000m3),  considering fuel  efficiency  gains.  Under 
these  conditions,  developing  this  option,  to  supply  off-grid  towns  in  Georgia  with  LNG  is  not 
considered viable. 

6.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
6.3.1 Supply of regasified LNG from in-country terminal 
Table 22 describes the key prerequisites for effective implementation of the option of establishing 
an in-country LNG import terminal in Georgia.  Critical/on-off prerequisites are the uninterrupted 
supply of LNG to the terminal i.e. the absence of any constraints for LNG vessels to pass through 
the Bosporus straits, and the existence of sufficient interest by potential users, as evidenced by 
market tests. Another important prerequisite relates to the availability of financing for the terminal, 
from  State  or  private  funds.  The  necessary  changes  in  the  legal  and  regulatory  framework, 
including permits and licenses, are also detailed. 

Table 22: Prerequisites for development of in-country LNG terminal 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Under the control of 
Turkey. Negotiations 
need to be initiated by 
Ukraine and Georgia 

High 

Decision of suppliers 

Uncertain 

Political 
1  Absence of any maritime 
or other constraints for 
LNG vessels to reach 
and supply the terminal   

Market 
1  Binding market tests 
confirming interest of 
suppliers to use terminal 
services before FID for 
the terminal is taken 

Critical - on/off 
condition, to ensure 
uninterrupted, prompt 
and adequate LNG 
supplies to the 
terminal 

Critical - on/off 
condition, to ensure 
there is secure and 
sufficient demand for 
the terminal’s services 
to make it viable. A 
successful market test 
requires suppliers to 
take a view on the 
competitiveness of 
LNG price vis-à-vis 
the gas import price 
that will emerge 
following new supply 
contracts with 
Azerbaijan, post 2026 
(as discussed in 
Section 6.2.1)    

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Legal & Regulatory 
1 

(Amendment to) energy 
law to allow establishing 
of LNG terminal, 
including ownership, 
regulation, TPA 
provisions and pricing 
regulation 

2  Permits and licenses for 
LNG terminal, including 
prerequisite technical 
studies, environmental 
and social impact 
assessment study 

3  Regulations and 

standards for the siting, 
design, construction and 
installation of LNG 
terminal, including 
infrastructures (jetty and 
connections to 
transmission system)  

4  Regulations for the 
operation of LNG 
terminal  

5  Regulatory license and 

process for accreditation 
of the terminal 

Financing 
1  Securing adequate 
financing for the 
investment in the 
terminal  
Infrastructure 
1  Connection of terminal 
to the transmission 
network and agreement 
between terminal 
operator and TSO 

To add the right to 
establish terminal and 
the applicable 
framework in the law 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

To ensure that all 
authorisations and 
preconditions are 
secured 

Legislators and policy 
makers need to set 
the rules so as to 
ensure safety, 
efficiency, quality and 
environmental 
protection   

Legislators and policy 
makers need to set 
the rules so as to 
ensure safe, efficient 
and environmentally 
conducive terminal 
operation    
Legislators and 
regulators need to set 
the rules (in 
accordance with EC 
Acquis), and terminal 
to comply   

To ensure that the 
terminal can go ahead 
(FID) 

Decision of State 
and/or investors 

High 

Under the sole control 
of Georgia 

Low 

For the terminal to be 
able to send 
regasified LNG to the 
system, in 
accordance with pre-
defined rules 

Table 23 outlines the key success factors for the implementation of the option of establishing an 
in-country LNG import terminal. These factors influence the speed of market development.  Some 
of the key success factors relate to the strength of the project promoter (access to finance etc.) 
and the existence of investment partners and experienced operator.  Other success factors relate 
to having a clear and effective strategy or the development of the terminal to avoid risks of delays 

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and  cost-overruns  and  having  a  contractual  strategy/model  that  allocates  fairly  risks  between 
contractors and developer. A conducive legal framework in the country as well as State support 
to the venture is important. For the terminal sustainability as a business, it is important to secure 
adequate customers, especially large off-takers, and to offer good service levels at a competitive 
price.  Finally, flexibility both in terms of terminal infrastructure and in terms of services, to changes 
in market conditions, enhances sustainability. 

Table 23: Key success factors for development of in-country LNG terminal 

Key success factors 

Rationale 

1  Strength (financial and otherwise) of the project 

promoter 

2  Bring-in strategic investment partners that can 

bring expertise to the venture and mitigate risks 

3  Bring-in experienced operator/management team 

4  Establishing an effective project delivery strategy 
for the terminal (for project teams, partners, 
contractors, consultants, stakeholder 
engagement, safety, financing, technical 
solutions, risk management, project control and 
monitoring etc.)  

5  Use contractual models that balance and align 

interests of terminal developers/operator (locking-
in key suppliers and reducing supply chain costs) 
and contractors/suppliers (having flexibility to deal 
with volatile commodity and service prices) 

Assurance for project completion and 
sustainability 
To ensure sustainability and mitigate 
business risks 
To ensure sustainability and mitigate 
business risks 
To ensure prompt and effective construction 

To ensure sustainability and mitigate 
business risks 

6  Host country has predictable and conducive legal, 

To avoid risks 

contractual and regulatory framework  

7  Competitive prices for the terminal’s services and 

To ensure sustainability  

good service levels 

8  Government is supportive in general for the 

To avoid delays and risks 

venture, and specifically ensures timely issuance 
of terminal permits and authorizations 

9  Existence of a market for LNG (regasified and in 
liquid form) that can sustain the terminal’s 
operations.  

10  Dependence on one major off-taker or several off-

takers.   

11  Terminal operation flexibility to adjust in case 

market conditions change (e.g. developing new 
services, pricing for unbundled services as 
opposed to bundled, flexibility to add new 
infrastructures such as jetty, tanks, truck loading 
facilities etc.)  

To ensure sustainability 

One major off-taker is preferable to lenders, 
but also increases dependence compared to 
situation of a portfolio of off-takers 
To ensure adaptability and sustainability  

Regasified  LNG  is  a  new  source  and  route  of  gas  supply  that  has  the  potential  to  enhance 
competition in the Georgian gas market, especially when the following factors apply:    

  Development of an organized day-ahead and within-day gas market to take advantage 

of the flexibility and liquidity of LNG. 

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  Completing  the  implementation  of  the  obligations  stemming  from  the  Energy 
Community related to market operation and gas network codes that will enhance non-
discriminatory and transparent access of regasified LNG to the Georgian network and 
market. 

6.3.2 Swaps of piped gas with regasified LNG in Turkish or EU terminals 
Table 24 describes the key prerequisites for performing swaps of regasified LNG in Turkey or SE 
Europe with piped gas delivered to Georgia. The prerequisites concern the interest by the involved 
parties to conclude a swap deal, the availability of LNG at prices that are conducive to the viability 
of the swap, and lack of any contractual barriers that would obstruct access to the SCP. 

Table 24: Prerequisites for swaps of piped gas with regasified LNG 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1 

Interest by all involved 
parties (BOTAS, 
potentially EU suppliers) 
to perform the swap. 
Agreement with BOTAS 
is necessary to allow 
swaps regardless of the 
terminal where LNG is 
delivered (Turkey or EU) 

2  The following two price 
preconditions should 
apply for a swap to be 
viable for both GOGC 
and BOTAS: 
 Price of LNG delivered 
at SCP is lower than 
the price of gas 
contracted by BOTAS 
in SCP. In case LNG 
price is higher, GOGC 
has to compensate 
BOTAS for the 
difference 

 Import prices of Azeri 
gas in the Georgian 
market are higher than 
the agreed price for the 
swap  

Contractual 
1  Terms & conditions of 
Azerbaijan – Turkey 
supply contract allow the 
delivery of gas by 

BOTAS currently is 
sole offtaker of Azeri 
gas through SCP, that 
can be swapped with 
LNG 

Negotiations of 
GOGC with BOTAS, 
and EU suppliers, if 
necessary 

Low to medium 

The price of swapped 
LNG has to be 
beneficial for all 
parties involved 

GOGC, BOTAS, and 
potentially EU 
suppliers 

Uncertain 

As there is no third-
party access to SCP, 
if BOTAS cannot 
have access to the 
Georgian offtake, the 

Under the control of 
BOTAS and SOCAR 

Uncertain 

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BOTAS at the Georgian 
offtake of SCP 

swap concept cannot 
be realized 

Other  than  experience  in  developing  swaps  and  procuring  LNG,  which  could  influence  the 
efficiency of this option, there are no other notable success factors. 

6.3.3 Use of LNG as engine fuel for trucks 
Table 25 describes the key prerequisites for effective implementation of the option of using LNG 
as engine fuel for trucks in Georgia. The prerequisites concern the appropriate price differential 
between LNG and diesel to ensure viability, as well as the necessary changes in the legal and 
regulatory  framework,  or  introduction  of  new  legislation  and regulations,  including  permits  and 
licenses. The prerequisites  relate  not  only  to  import  and operation of  trucks,  but  extend to the 
supply  chain  for  LNG  concerning  trucks: filling stations, truck  loading facilities at  an  in-country 
LNG  terminal,  in  case  this  option  is  implemented  and  LNG  is  sourced  from  there,  liquefaction 
plants and truck loading facilities at these plants, in case LNG is sourced from piped gas in the 
country. The interest of sufficient truck owners to switch to LNG, and the attraction of investments 
to develop the necessary infrastructure (filling stations, liquefaction facilities) is also critical for the 
development of the market. 

It is noted that the prerequisites related to the import of LNG and the development of relevant 
import  facilities  in  Georgia  are  listed  separately  in  Section  6.3.1,  and  the  perquisites  to  the 
development of a liquefaction and export terminal are listed in Section 6.3.4. 

Table 25: Prerequisites for development of LNG as engine fuel for trucks 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and diesel (as discussed 
in Section 6.2.3)  

Critical – on/off 
condition, as 
switching to LNG 
requires an attractive 
price of LNG vis-à-vis 
diesel at the end use 

2 

Interest of a critical mass 
of truck owners to switch 
to LNG 

Viability of the option 
is dependent on 
having a minimum 
market size to justify 
investments  

LNG and diesel 
source prices are 
determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is 
sourced from an in-
country liquefaction 
facility, in which the 
price is determined 
by gas import 
contracts)   
Decision of truck 
owners 

Uncertain 

Medium 

Legal & Regulatory 
1  Regulations and 

standards for the design, 

Need to ensure 
safety, efficiency, 

Under the sole 
control of Georgia 

Low 

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manufacturing and 
installation of the LNG 
fueled trucks and 
different components 
(e.g. pressure control 
regulator, LNG filling 
receptacle etc.) for 
approval of LNG 
vehicles import and 
operation47, 48 

2  Road regulations for 
circulation of LNG 
fuelled vehicles 

3  LNG and L-CNG filling 
stations permits and 
licences, notably building 
license, operation 
license, and business 
license49 

4  LNG and L-CNG filling 
stations regulatory 
guidelines49 in relation to 
set-up and construction 
(e.g. distance, tank 
levels etc.), operation 
(e.g. guarantee sufficient 
product), and 
maintenance (planned 

quality and 
environmental 
protection.  There are 
various European 
and international 
standards that could 
be incorporated in 
national legislation as 
the basis for granting 
approval. 
Need to ensure 
safety, by stipulating 
any restrictions in 
movement e.g. in 
cases of heavy traffic, 
adverse weather 
conditions affecting 
visibility and road 
conditions etc.  
Need to ensure the 
eligibility of the 
selected site for the 
station, compliance 
with operational 
obligations (e.g. 
opening hours, 
station throughput, 
safety obligations, 
and business 
registration of the 
entity.  The licenses 
require testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  
Need to ensure 
safety and efficiency 
of the station.  The 
regulations require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

47 DG MOVE, LNG Blue Corridors, Vehicle Regulations - State of the Art, December 2013 
48 DG MOVE, LNG Blue Corridors, LNG stations Regulations -State of the art, December 2013 
49 DG MOVE, LNG Blue Corridors, Guidelines for set up & operation of stations, May 2015 

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maintenance work in a 
programmed schedule) 
of the station. 

5  Road safety regulations 
for trucks carrying LNG 
to the filling stations.   

6  Regulations governing 

TPA of LNG carrying 
trucks at LNG terminal 
(in case an in-country 
LNG terminal with truck 
loading facilities is 
developed) 

7  Regulations governing 

loading of LNG to trucks 
at LNG terminal facilities 
(in case an in-country 
LNG terminal with truck 
loading facilities is 
developed) 

8  Regulations governing 
pricing of LNG terminal 
truck loading facilities (in 
case there is an LNG 
terminal with truck 
loading facilities, and 
there is price regulation 
for third party access to 
such facilities) 

9  Permits and licenses, 
including technical 
specifications, for truck 
loading facilities at LNG 
terminal (in case an in-
country LNG terminal 
with truck loading 
facilities is developed) 

before licences are 
granted and after 
(inspection/checks for 
compliance)  
LNG transportation 
carries some 
potential hazards, 
linked to flammability 
as well as the impact 
of cryogenic fuel 
exposure or 
Leakage.  There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR.   
Need to ensure 
transparent and non-
discriminatory access 
of truck operators to 
the truck loading 
facilities 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc.  
Need to have 
published tariffs for 
truck loading facility 
services at the 
terminal, that are 
non-discriminatory for 
users, and 
regulations for the 
allowed costs in such 
tariffs 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

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10  Permits and licences, 
including technical 
specifications, for 
liquefaction facilities (in 
case LNG is sourced 
from the gas network 
and loaded on to trucks)  

11  Permitting process, 
including technical 
specifications, for truck 
loading at liquefaction 
facility (in case there is a 
liquefaction facility)  

12 

(Amendment to) law to 
specify whether/which 
type of liquefaction 
facilities are regulated 
(TPA and pricing) 
13  Regulations governing 
TPA of LNG trucks at 
liquefaction facility (in 
case there is a regulated 
liquefaction facility) 

14  Regulations governing 

pricing of liquefaction 
facility (in case there is a 
regulated liquefaction 
facility) 

Infrastructure 
1 

Interest of investors to 
implement necessary 
infrastructure (filling 
stations, in-country 
liquefaction facility) 

Need to have permits 
and regulations for 
site requirements, 
health and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc. 
Need to have 
published tariffs for 
use of the 
liquefaction plant 
services, that are 
non-discriminatory for 
users, and 
regulations for the 
allowed costs in such 
tariffs 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
trucks to be able to 
operate  

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Under the sole 
control of Georgia 

Low 

Decision of investors  Medium 

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Table 26 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for trucks. These factors influence the speed of market development.  Some of the 
key success factors relate to the State providing support to catalyze investments in LNG trucks 
and filling stations. Others relate to having a regulatory framework that favors ‘cleaner’ LNG use 
in trucking and punishes more ‘dirty fuels’.  State can also regulate the level of subsidies in other 
fuels,  to  make  LNG  more  competitive.  Other  factors  relate  to  the  role  of  State  and  State 
organizations  to  foster  changes  and  to  support  investors  (one-stop-shop).  Finally,  the  role  of 
information campaigns for consumers, users and investors is important to overcome resistance 
to change and to boost interest. 

Table 26: Key success factors for development of LNG as engine fuel for trucks 

Key success factors 

Rationale 

1  Conducive fiscal framework (low taxes, low import 
duties, availability of state grants and rebates) for 
the purchase of LNG fuelled trucks or the 
retrofitting of existing trucks to LNG.  

2  Setting and enforcing circulation restrictions for 
trucks that use older generation engines with 
higher emissions detrimental to the environment 
(e.g. Euro 4 fuels)  

3  Reduction of subsidies and favourite tax treatment 

of fuels competing with LNG, to make LNG more 
competitive and incentivise its use. 

4  Conducive fiscal framework (specific concession 

regimes, tax holidays, state grants50) conducive to 
investment in construction of new LNG filling 
stations, or for retrofitting petrol stations to include 
LNG, or for retrofitting CNG stations to offer also 
LNG (L-CNG). Also, state co-funding of LNG R&D 
activities 

5  Awareness and promotion campaigns for LNG. 

6  Having a ‘National champion’ e.g. the Ministry of 
Economy or a State Committee that includes gas 
company and other key stakeholders.  The role of 
the National champion would be to coordinate the 
set-up of the required legal and regulatory 
framework, develop and implement policy and 
incentives, to remove obstacles in for LNG market 
development and to act as one-stop-shop for 
investors. Its role would also include planning the 
number and location of LNG filling stations and 
facilities (possibly introducing limited concessions 
for infrastructure) so as to avoid stranded 
investments.    

Having sufficient network of LNG stations is a 
major success factor. Incentivising private 
investment is one way to develop the market.   

Consumers should be educated as to the 
potential features and benefits of LNG in 
transport.  Investors should be informed on 
the opportunities available.  Such campaigns 
can counter resistance to change and speed 
up interest. 
Many initiatives are slowed down by 
regulatory gaps or unclear legislation, lack of 
implementing administrative mechanisms 
and bureaucracy and lack of action.  Such 
problems are exacerbated due to lack of 
awareness and resistance to change or 
inertia.  For example, customs may not be 
familiar with rules and regulations for the new 
LNG vehicles and delay their clearance.   

50 ‘Connecting Europe Facility’, for example, provides grant to co-finance investment in LNG filling stations in the EU 

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6.3.4 Development of liquefaction and export terminal 
Table 27 describes the key prerequisites for effective implementation of the option of establishing 
an in-country liquefaction and LNG export terminal in Georgia.  Critical/on-off prerequisites relate 
to the existence of sufficient long-term and appropriately priced contracts for the supply of gas to 
the  liquefaction  plant,  and  for  ensuring  long-term  sales  contracts  of  the  produced  LNG  to 
customers. Another important prerequisite relates to the availability of funding for the very large 
investments  for  the  plant  and  terminal.  The  necessary  changes  in  the  legal  and  regulatory 
framework, including permits and licenses, are also detailed, as well as the infrastructure needs 
of the plant. 

Table 27: Prerequisites for development of liquefaction and export terminal 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Existence of long-term 
supply contracts of gas 
to the liquefaction plant, 
at prices that make LNG 
produced competitive at 
the target markets 

2  Securing sufficient long-
term sales of LNG that 
provide assurance for 
the plant and terminal 
revenues 
Legal & Regulatory 
1 

(Amendment to) energy 
law to allow establishing 
of liquefaction plant and 
export terminal, 
including ownership, 
regulation, TPA 
provisions and pricing 
regulation 

2  Permits and licenses for 
the plant and LNG 
export terminal, 
including prerequisite 
technical studies, 
environmental and 

Critical - on/off 
condition, to ensure 
viability of the 
liquefaction plant (as 
discussed in Sections 
7.2.3 and 8.2.3). 
Currently no gas is 
available, and 
supplies can be 
possible only in case 
new fields are 
developed in 
Azerbaijan and/or 
supplies from Central 
Asia are forthcoming 
Critical – on/off 
condition, to ensure 
there is sufficient 
demand for the 
terminal’s services  

To add the right to 
establish plant and 
export terminal, and 
the applicable 
framework, in the law 

Uncertain 

Under control of 
Azerbaijan, and 
potentially Central 
Asia countries that 
may supply gas to the 
plant 

Decision of suppliers 
at the target markets 

Uncertain 

Under the sole control 
of Georgia 

Low 

To ensure that all 
authorisations and 
preconditions are 
secured 

Under the sole control 
of Georgia 

Low 

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social impact 
assessment study 

3  Regulations and 

standards for the siting, 
design, construction and 
installation of the 
liquefaction plant and 
export terminal, 
including infrastructures 
(jetty and connections to 
transmission system)  

4  Regulations for the 

operation of LNG 
terminal  

5  Regulatory license and 

process for 
accreditation of the 
plant and terminal 

Financing 
1  Securing adequate 
financing for the 
investment in the 
liquefaction plant and 
export terminal  

Infrastructure 
1  Connection of the 

liquefaction plant to the 
transmission network 
and agreement between 
plant operator and TSO 

2  Absence of any 

maritime or other 
constraints for empty 
LNG vessels to enter 
the Black Sea, and load 
at the liquefaction plant   

Legislators and policy 
makers need to set 
the rules so as to 
ensure safety, 
efficiency, quality and 
environmental 
protection   

Legislators and policy 
makers need to set 
the rules so as to 
ensure safe, efficient 
and environmentally 
conducive terminal 
operation    
Legislators and 
regulators need to set 
the rules (in 
accordance with EC 
Acquis), and operator 
to comply   

To ensure that the 
terminal can go 
ahead (FID) 

For the terminal to be 
able to send 
regasified LNG to the 
system, in 
accordance with pre-
defined rules 
To ensure LNG can 
be uninterruptedly, 
promptly and 
adequately offtaken 
from the terminal 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

Under the sole control 
of Georgia 

Low 

Decision of investors 
and State 

High 

Under the sole control 
of Georgia 

Low 

Under control of 
Turkey 

Low 

Table 28 outlines the key success factors for the implementation of the option of establishing an 
in-country  liquefaction  plant  and  LNG  export  terminal.  These  factors  influence  the  speed  of 
development of the option.  Some of the key success factors relate to the strength of the project 
promoter  (access  to  finance  etc.)  and  the  existence  of  investment  partners  and  experienced 
operator.  Other success factors relate to having a clear and effective strategy or the development 
of the terminal to avoid risks of delays and cost-overruns and having a contractual strategy/model 
that allocates fairly risks between contractors and developer. A conducive legal framework in the 
country as well as State support to the venture is important. For the export terminal sustainability 

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as a business it is important to secure adequate customers, especially large off-takers, and to 
offer  good  service  levels  at  a  competitive  price.    Finally,  flexibility  of  the  export  terminal’s 
infrastructure to changes in market conditions enhances sustainability. 

Table 28: Key success factors for development of liquefaction and export terminal 

Key success factors 

1  Strength and experience (financial and 
otherwise) of the project promoter 

2  Bring-in strategic investment partners (especially 

off-takers/buyers of LNG)  

3  Establishing an effective project delivery strategy 
for the plant and export terminal (for project 
teams, partners, contractors, consultants, 
stakeholder engagement, safety, financing, 
technical solutions, risk management, project 
control and monitoring etc.)  

4  Use contractual models that balance and align 
interests of export terminal developers/operator 
(locking-in key suppliers and reducing supply 
chain costs) and buyers (having flexibility to deal 
with volatile commodity and service prices) 
5  Host country has predictable and conducive 
legal, contractual and regulatory framework  

Rationale 

Assurance for project completion and 
sustainability 
To ensure sustainability and mitigate 
business risks 
To ensure prompt and effective construction 

To ensure sustainability and mitigate 
business risks 

To avoid risks 

6  Government support for timely issuance of 

To avoid delays and risks 

terminal permits and authorizations 

7  Competitive prices for the terminal’s services and 

To ensure sustainability  

good service levels 

8  High proportion of long-term sales contracts with 

9 

buyers    
Terminal operation flexibility to adjust in case 
market conditions change (e.g. flexibility to add 
new infrastructures such as jetty, tanks) 

To provide more secured revenues and 
ensure sustainability 
To ensure adaptability and sustainability  

6.4 Priorities and policy directions 
LNG  for  gas  swaps  could  be  a  priority  option,  as  it  does  not  require  development  of  new 
infrastructures and can be implemented in a short time provided the underlying economics of the 
swap of LNG for gas appeal to the concerned parties.   

The  LNG  receiving  terminal  is  a  long-term  option,  on  account  of  having  to  fulfil  several 
prerequisites, some of which are critical/on-off, that affect the readiness to implement this option, 
notably the uninterrupted passage of LNG vessels through the Bosporus Straits and securing of 
a sufficient market for regasified LNG. A final decision on implementing the terminal should be 
made only in case of potential price hikes when existing Georgian contracts with Azerbaijan are 
renewed, post 2026, to ensure the viability of the terminal. 

The  establishment  of  a  large  liquefaction  plant  and  export  terminal  is  also  a  long-term  option, 
subject  to  securing  adequate  gas  supplies  from  Azerbaijan  and/or  Central  Asia  for  LNG 
conversion, and long-term sales to LNG buyers in target markets. 

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The option of LNG as fuel for trucks could be viable using an in-country mini liquefaction facility, 
and could be done in a short-term horizon, as it involves decisions only of local actors, but the 
high investment costs in required infrastructure necessitate a large number of LNG fueled trucks 
for  viability.  On  the  other  hand,  LNG  as  fuel  for  trucks  with  LNG  supplied  from  an  in-country 
receiving  terminal,  in  case  such  terminal  was  established,  would  require  a  smaller  number  of 
trucks, to be viable, but is a longer term option, as the relevant infrastructure is dependent on a 
number of factors controlled by third, external, parties. The Government could assess feasibility 
of this option in detail further and take relevant policy actions. These policies could encompass, 
at  the minimum,  having a legal  and regulatory framework  conducive  to  the  development  of an 
LNG supply chain, and could expand to cover incentives for the use of LNG.   

6.5 Proposed actions  
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the identified applicable LNG market development options.  

Table 29: Proposed preparatory actions for developing the identified LNG options in Georgia 

Proposed Actions 

Timing 

Initial / Preparatory Actions 
1  Assess existence of any contractual barriers for implementing 

2 

swaps through SCP 
Initiate dialogue with Turkish authorities regarding passage of 
LNG vessels through the Bosporus Straits 

3  Perform feasibility study for the development of LNG receiving 

terminal 

4  Perform feasibility study for the development of liquefaction 
and export terminal, including assessment of when (and if) 
sufficient gas supplies from the Caspian Region will become 
available to allow consideration of the liquefaction terminal 

5  Perform feasibility study for the use of LNG as fuel for trucks 
6  Develop a national policy framework for the use of LNG in road 

transport, deciding on the role that the State wishes to 
undertake 

Implementation Actions concerning swaps 
7 

Initiate negotiations and establish MoU with relevant 
stakeholders for swap framework 

8  Enhance awareness on global LNG market, trading and 

trends, so as to be ready to secure LNG volumes for the swap 
when the opportunity arises 

Immediate 

Immediate 

Short-term / dependent on the 
progress of negotiations with 
Turkey 
Medium-term / dependent on the 
availability of Caspian gas 
supplies 

Immediate 
Short-term / After the study is 
concluded (in case it is positive 
and Georgia decides to pursue) 

Short-term / based on possibility 
to perform swaps  
Short-term / based on possibility 
to perform swaps 

Implementation Actions concerning large LNG infrastructures (receiving terminal, liquefaction 
and export terminal) 
9  Gauge and secure the market’s interest to use the LNG 

Medium-term 

receiving terminal (e.g. binding market test) 

10  Explore investors’ interests in the LNG receiving terminal 
11  Gauge and secure the interest of gas producers to use the 
liquefaction terminal and suppliers in the region to procure 
LNG 

Medium to long-term 
Medium to long-term 

12  Explore investors’ interests in the liquefaction and export 

Long-term 

terminal 

Implementation Actions aiming at developing use of LNG in road transport 

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13  Prepare the regulatory and legal framework (legal 

14 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the LNG supply chain 
If the State undertakes a proactive role in developing 
infrastructure, prepare the incentive mechanisms to attract 
investments 

15  Conduct awareness raising campaigns to attract end-users 

and investors’ interest 

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  

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7  LNG Market Prospects in Moldova 

7.1 Identification of applicable LNG market development options  
An overview of the Moldovan gas sector is provided in Annex 1.5. Following the analysis of the 
gas market information, and discussions with stakeholders during the field visit to the country, the 
key findings related to the development of LNG markets in Moldova are as follows: 

  Gas-to-gas  competition  from  LNG  could  be  applicable  in  Moldova.    Currently  import 
prices  of  Russian  gas  (only  supplier  of  the  market)  are  lower  than  LNG.  However, 
regasified LNG supplies could be sourced for diversification of supply purposes. There 
are  multiple  potential  import  routes:  from  Polish  Świnoujście  LNG  terminal  and 
Lithuanian  Klaipeda  LNG  terminal  (once  GIPL  is  completed)  through  Poland  and 
Ukraine; from the Greek Revythoussa LNG terminal, through Bulgaria – Romania, after 
completion  of  the  reverse  flow  of  Trans-Balkan  pipeline  and  of  the  Iasi  –  Ungheni  – 
Chisinau  pipeline;  from  Croatian  Krk  LNG  terminal,  through  Hungary  and  Ukraine, 
provided  that  bottlenecks  in  the  Hungarian  system  are  resolved.  In  case  an  LNG 
receiving terminal in Ukraine is built, in the Odessa area, this could also be a source 
for regasified LNG supplies to Moldova, due to existing interconnections and proximity 
of  the  Moldovan  system  to  Odessa.  In  case  a  liquefaction  terminal  is  developed  in 
Georgia, in combination with a Ukrainian receiving terminal, regasified LNG of Caspian 
origin could be supplied to the Moldovan market through Ukraine.    

  Gas-to-other  fuels  competition  could  be  applicable  in  Moldova  through  LNG  use  for 
peak shaving. Moldova has no gas storage and gas flows fluctuate significantly. Use 
of  small-scale  LNG storage for  peak  shaving  at the  Chisinau  and Belts  District  CHP 
stations, can reduce dependence on other fuels (e.g. oil during winter) and  enhance 
security of energy supply   

  Gas-to-other fuels competition is not applicable to remote/off-grid customers. All towns 

are gasified and reportedly off-grid consumers are not interested to use gas 

  Gas-to-other fuels competition does not seem applicable to road and water transport.  
International long-haul traffic through Moldova is very small. There is also very limited 
vessel traffic in Moldovan waterways. Therefore, it seems that there is no potential for 
LNG to be used in transport sector 

Based on the above analysis, the applicable LNG market development options for Moldova, for 
gas-to-gas and gas-to-other fuels competition, are presented in Table 30. Regasified LNG can be 
sourced from neighbouring EU terminals (Świnoujście, Klaipeda, Revythoussa, Krk), or a potential 
LNG receiving terminal in Ukraine. Development of the latter is subject to either Ukraine agreeing 
with Turkey for the passage of LNG through the Bosporus Straits, or, in the long-term, LNG of 
Caspian  origin  being  available  to  be  produced  and  exported  from  a  liquefaction  terminal  in 
Georgia  (as  currently  there  are  no  available  supplies  of  Caspian  gas  to  feed  such  a  potential 
infrastructure).  

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LNG for gas-to-other fuels competition can be sourced either from the Ukrainian LNG terminal or 
an in-country mini liquefaction facility connected to the Moldovan transmission system. 

Table 30: Applicable options for LNG market development in Moldova 

Options for LNG market development 

Gas-to-Gas 
Competition 

Regasified LNG sourced from 
neighbouring EU terminals 
Regasified LNG sourced from a potential 
LNG terminal in Ukraine 
Regasified LNG sourced from a potential 
liquefaction terminal in Georgia, through a 
receiving terminal in Ukraine 

Gas-to-Other 
Fuels Competition 

LNG storage for peak shaving at the 
Moldovan CHP stations 

Sources of supply 
Świnoujście, Klaipeda, Revythoussa, 
Krk receiving terminals51 
Potential receiving terminal in 
Ukraine 

Potential liquefaction terminal in 
Georgia 

  LNG truck loading in Świnoujście 

and/or Klaipeda terminals 

  Potential receiving terminal in 

Ukraine 

  In-country mini liquefaction facility 

7.2 Assessment of viability of applicable LNG market options 
7.2.1 Supply of regasified LNG from neighbouring EU terminals 
This LNG market development option can be considered as potentially viable for Moldova in case 
regasified LNG can arrive to the Moldovan market from the neighbouring EU LNG terminals at a 
price competitive to that of the existing gas supply sources, taking into consideration all relevant 
transportation costs.  

To  estimate  the  competitiveness  of  LNG,  netback  analysis  was  performed,  starting  from  the 
wholesale gas price in Moldova, up to each examined receiving terminal, taking into consideration 
in-country transportation costs, pancaking of the in-between cross-border tariffs and charges for 
the use of the receiving terminal. The detailed approach and calculations are described in Annex 
2.1. 

The  market  price  applied  in  the  calculations  is  the  regulated  price  for  entry  in  the  Moldovan 
transmission system52 (151.5 EUR/1000 m3). The netback analysis performed for each examined 
route is presented in Figure 14 to Figure 17. 

Figure 14: Netback analysis at maximum price for route Poland->Ukraine->Moldova 

51 Other  potential  supply  options  include  the  Marmara  Ereglisi  terminal  in  Turkey  and  the  planned  Alexandroupolis 
FSRU in Greece and Gdansk FSRU in Poland. The netback analysis of these options would wield similar results with 
the examined terminals 
52 Source: Moldovan National Agency for Energy Regulation Decision No 88/2018 

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Figure 15: Netback analysis at maximum price for route Lithuania->Poland->Ukraine->Moldova 

Figure 16: Netback analysis at maximum price for route Greece->Bulgaria->Romania->Moldova 

Figure 17: Netback analysis at maximum price for route Croatia->Hungary->Ukraine->Moldova 

Figure 18 presents the results of the netback analysis for all assumed wholesale prices, and all 
examined routes to Moldova. 

Figure 18: Netback analysis results for routes of regasified LNG from EU terminals to Moldova  

The results of the analysis show that due to the low gas prices in Moldova, supply of regasified 
LNG cannot be competitive under the examined assumptions and market conditions.  

Nevertheless, supplies of LNG could be considered as a way to enhance Moldova’s security of 
supply. Economic analysis for this LNG option was conducted, to assess whether the security of 
supply benefits can outweigh the premium that would have to be paid for the supplied LNG. The 
detailed approach and calculations are described in Annex 4.1. 

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The  economic  analysis  results  show  that  the  use  of  supplies  of  LNG  for  security  of  supply 
purposes  appears  to  be  beneficial  for  the  Moldovan  market,  as  it  would  eliminate  potential 
demand curtailment, in case of a disruption in Russian gas supplies (Figure 19). 

Figure  19:  Present  value  of  economic  costs  and  benefits  for  supply  of  regasified  LNG  from  EU 
terminals to Moldova 

The impact of LNG supplies is also highlighted though the demand curtailment indicator (Annex 
4.4), that is reduced to zero  in case regasified LNG is used in case of a disruption of Russian 
imports.  

Based  on  the  above  analysis,  the  supplies  of  regasified  LNG  from  neighbouring  terminals  to 
Moldova can be considered as a potentially viable LNG option. 

7.2.2 Supply of regasified LNG from Ukrainian terminal 
This LNG market development option can be considered as potentially viable for Moldova in case 
LNG can arrive at a Ukrainian receiving terminal at a price competitive to that of the existing gas 
supply  sources  for  the  Moldovan  market,  taking  into  consideration  all  relevant  transportation 
costs.  Agreement  with  Turkey  for  passing  of  LNG  vessels  through  the  Bosporus  Straits  in  an 
on/off precondition for this option to be developed. 

The Ukrainian terminal is planned to be located near Odessa. The development of an FSRU with 
send-out capacity of 5 bcm/yr is assumed. 

Netback analysis was performed, starting from the gas price in Moldova, up to the terminal, taking 
into  consideration  in-country  transportation  costs  in  Moldova,  cross-border  tariffs  at  the 
interconnection with Ukraine and charges for the use of the terminal. The detailed approach and 
calculations are described in Annex 2.2.  

As the charges of the Ukrainian terminal depend on its utilization rate, we examine 3 scenarios of 
low (30%), medium (50%) and high (70%) utilization.  

Figure 20 presents the results of the netback analysis.  

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Figure 20: Netback analysis results for supplies of regasified LNG to Moldova from a terminal in 
Ukraine, all examined utilization rates 

LNG price in the Black Sea can be expected to be higher than that of the Mediterranean, due to 
the additional transport costs and fees for crossing through the Bosporus Straits. With LNG import 
price at the Greek Revythoussa terminal 210 EUR/1000m3 in Q2 201953, it is assumed that the 
corresponding price in the Black Sea will be at least 5% higher. 

The results of the analysis show that, as in the case of supplies from EU terminals, due to the low 
gas  prices  in  Moldova,  supply  of  regasified  LNG  through  a  Ukrainian  terminal  cannot  be 
competitive under the examined assumptions and market conditions. 

The economic analysis of the Ukrainian LNG terminal (see Annex 4.1) shows that, in case the 
infrastructure is implemented, Moldova would have access to an additional supply route, through 
which to address a potential disruption of Russian gas supplies. It should be stressed, however, 
that Moldova could also enhance its security of supply by considering other options, such as the 
supply  of  regasified  LNG  from  existing  LNG  terminals  in  the  region,  analysed  in  the  previous 
Section.   

7.2.3 Supply of regasified LNG from Georgian liquefaction terminal 
This LNG market development option can be considered as potentially viable for Moldova in case 
regasified LNG can arrive though a Ukrainian receiving terminal from a liquefaction terminal in 
Georgia, at a price competitive to that of the existing gas supply sources for the Moldovan market, 
taking into consideration all relevant transportation costs. This option can only be developed in 
the  long-term,  provided sufficient  gas  supplies  of  Caspian  origin  are  secured  for  the  Georgian 
terminal, for liquefaction and export. 

The liquefaction terminal in Georgia is assumed to have an LNG production capacity of 2 bcm/yr, 
and a utilization rate of 90% (with LNG supplied to Eastern Partners and EU countries). For the 
Ukrainian receiving terminal, the assumptions described in Section 7.2.2 above, concerning the 
terminal and market wholesale prices are applied. 

53 Source: DG Energy, “Gas Market Report Q2 2019” 

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Netback analysis was performed, starting from the gas price in Moldova, up to the Georgian gas 
market,  taking  into  consideration  in-country  transportation  costs,  cross-border  tariffs  at  the 
interconnection with Ukraine and charges for the use of the receiving terminal in Ukraine and the 
liquefaction terminal in Georgia. The detailed approach and calculations are described in Annex 
2.3.  

The  results  are  negative  (i.e.  costs  are  not  recovered),  due  to  the  low  gas  price  in  Moldova. 
Therefore, gas liquefied in the Black Sea cannot be commercially viable for Moldova under the 
examined assumptions and market conditions.  

Supply of LNG through Ukraine would provide Moldova with access an additional source of gas 
(Annex 4.3); however, as shown in Section 7.2.1, the option of supplies of regasified LNG from 
existing LNG terminals in the region can diversify the market’s supply sources on a shorter-term 
and without the need for additional infrastructure. 

7.2.4 Use of LNG for peak shaving at CHP stations 
In this option, regasified LNG is used at the Moldovan CHP stations as a back-up supply source, 
to ensure continuity of electricity generation in case the regular supply of piped gas is distorted 
(for example due to fluctuations in gas flows through the system, or a disruption in imported gas). 

The  data  for  the  CHP  stations  required  to  analyse  this  option  further  were  not  available, 
consequently netback and economic analysis was not conducted within the frame of this Study.  

Implementation of the option would require development of an LNG storage and regasification 
facility at the CHP sites that can be supplied with LNG either from neighbouring terminals, or from 
a mini liquefaction facility. As the main purpose of this option is to enhance security of supply, and 
not to provide a competitive supply source to piped gas, it can be expected that the development 
of  the required  infrastructure  would not  be  viable.  Economic  analysis  should  be  carried  out,  to 
examine whether the resulting security of supply benefits can outweigh the costs for developing 
the LNG supply chain. 

7.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
7.3.1 Supply of regasified LNG from neighbouring EU terminals 
The  supply  of  regasified  LNG  to  Moldova  from  neighboring  EU  terminals  can  be  carried  out 
without  major  market  preconditions,  as  it  concerns  specific  quantities  for  security  of  supply 
purposes.  

Interconnection  Agreement  between  Moldovatransgaz  and  Ukrtransgaz, 
Signing  of  an 
establishing  business  rules  in  line  with  the  Interoperability  Network  Code  (Regulation  (EU) 
2015/703),  currently  under  negotiation  by  the  two  parties,  is  important  to  facilitate  flows  of 
regasified  LNG  through  Ukraine  to  Moldova.  Additionally,  there  should  be  sufficient  available 
capacity at the interconnection points, to allow supply of regasified LNG. 

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7.3.2 Use of LNG for peak shaving at CHP stations 
Table 31 describes the key prerequisites for effective implementation of the option of using LNG 
for peak shaving at CHP stations in Moldova. The prerequisites concern the existence of rules 
and regulations allowing the development of LNG storage and regasification, the transportation 
of LNG via trucks (in case this option of supply is selected) and the development of a liquefaction 
facility (in case such a facility is developed at the CHP station). 

Table 31: Prerequisites for use of LNG for peak shaving at CHP stations 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Under the sole control 
of Moldova 

Low 

Under the sole control 
of Moldova 

Low 

Under the sole control 
of Moldova 

Low 

Prerequisites 

Rationale 

Legal & Regulatory 
1  Regulations 

and 
standards  for  the  siting, 
design, construction and 
LNG 
installation 
storage 
and 
regasification 
installations at the CHP 

of 

2  Road safety regulations 
for trucks carrying LNG 
to the CHP stations.   

3  Permits and licences, 
including technical 
specifications, for 
liquefaction facilities (in 
case gas will be 
liquefied at the CHP 
station)  

Need to ensure safety, 
efficiency,  quality  and 
environmental 
protection  by  having 
standards  concerning 
and 
LNG 
storage 
including 
vaporisers, 
mobile LNG tanks and 
vaporizers  
LNG transportation 
carries some potential 
hazards, linked to 
flammability as well as 
the impact of 
cryogenic fuel 
exposure or 
leakage. There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR.   
Need to have permits 
and regulations for 
site requirements, 
health and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 

As the development of a peak shaving facility is purely for security of supply reasons, and not for 
commercial purposes, there are no key factors conducive to its implementation. 

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7.4 Priorities and policy directions 
The supply of regasified LNG from neighbouring LNG terminals to the Moldovan market is not a 
viable  option,  on  account  of  lack  of  price  competitiveness  of  LNG  to  imported  low  priced  gas. 
However, in view of the security of supply benefits, which even small LNG volumes could provide, 
as indicated in the CBA carried out, this option could merit further examination by the relevant 
stakeholders (Government, Moldovagas). This option can go ahead over a short-term horizon, as 
it is not impeded by infrastructure constraints.  

Additionally, the option of using LNG for peak shaving of CHP plants could also be an important 
option realized over the short-term to enhance security of energy supply in the country. As such, 
it needs to be assessed from a cost benefit perspective to determine its priority.   

The  options  of  Moldova  being  supplied  with  LNG  from  Ukraine  and/or  Georgia  are  highly 
dependent  on  the  development  of  LNG  receiving  terminals  in  these  countries,  with  significant 
uncertainties 
the 
maturity/readiness to implement these options. 

the  on/off  requirements  and  prerequisites, 

in  view  of 

that  affect 

7.5 Proposed actions  
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the identified applicable LNG market development options.  

Table 32: Proposed preparatory actions for developing the identified LNG options in Moldova 

Proposed Actions 

Timing 

Initial / Preparatory Actions 
1  Enhance awareness on global LNG market, trading and trends, 
so as to be ready to secure LNG volumes for security of supply 
reasons, when the opportunity arises 

2  Perform detailed market options’ analysis for the supply of 
regasified LNG to Moldova, and analyze the options for 
Moldovagas to recover the costs (increase of prices, PSO, 
grant, etc.) 

3  Conclude interconnection agreement with the Ukrainian TSO 
4  Perform feasibility study for the development of peak shaving 
facility at the CHP stations and analyse the financing options 
and the recovery of the investment costs increase of prices, 
PSO, grant, etc.) 
Implementation Actions 
5  Conclude agreement for procuring LNG for security of supply 

6  Prepare the regulatory and legal framework (legal 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the peak shaving facility 
at the CHP stations 

Immediate 

Immediate 

Immediate 
Immediate 

Short-term (in case Moldova 
decides to pursue this option) 
Short-term (in case Moldova 
decides to pursue this option) 

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8  LNG Market Prospects in Ukraine 

8.1 Identification of applicable LNG market development options 
An overview of the Ukrainian gas sector is provided in Annex 1.6. Following the analysis of the 
gas market information, and discussions with stakeholders during the field visit to the country, the 
key findings related to the development of LNG markets in Ukraine are as follows: 

  Gas-to-gas competition from  LNG could be applicable in Ukraine. There are multiple 
pipeline  routes  through which regasified  LNG can  be  imported,  now  or  in  the future. 
LNG can come via Poland (from Świnoujście LNG terminal), and from Klaipeda LNG 
terminal (once GIPL is completed) through the existing interconnection or the planned 
new Poland – Ukraine interconnection54. LNG can also come via Slovakia and Hungary 
(e.g. Krk or Italian LNG terminals). Moreover, LNG can  be sourced via Hungary (e.g. 
Krk or Italian LNG terminals), provided that bottlenecks in the Hungarian system are 
resolved,  as  well  as  through  Romania  (Greek  and  Turkish  LNG  terminals),  after 
reverse flow of the Trans-Balkan pipeline. It is noted that LNG import does not involve 
route  diversification,  as  it  will  be  transported  through  the  routes  used  for  piped  gas 
supplies, and therefore price competitiveness is the key driver. Furthermore, an issue 
to consider would be the expected impact of discontinuation or decrease in Russian 
transit  volumes  on  reduced  Ukraine  import  capacities  with  Slovakia,  Poland  and 
Hungary. 

  Ukraine is interested to establish its own LNG import terminal in the Black Sea, near 
Odessa.  An  LNG  terminal  could  provide  regasified  LNG  to  customers  through 
connection  with  Ukrainian  transmission  grid.  Additionally,  given  adequate  terminal 
infrastructure (storage and truck loading facilities), LNG could be supplied directly to 
off-grid customers and for new gas uses (filling stations for trucks and ships etc.). The 
option  of  establishing  an  LNG  receiving  terminal  is  nevertheless  contingent  upon 
Turkey’s  agreement  to  allow  LNG  vessels’  passage  through  the  Bosporus  Straits. 
Another LNG project being examined is a small scale LNG receiving terminal in Reni, 
aiming to be used for bunkering and covering local gas needs.   

  Ukraine  can  also  import  LNG  by  trucks  and/or  trains.  Ukraine  has  road  and  rail 
connections to Poland (and on to Lithuania) that could be used to transport LNG with 
trucks from the Świnoujście and Klaipeda terminals, and via rail once the rail loading 
facility is developed at the Świnoujście terminal.   

  Gas-to-other  fuels  competition  from  LNG  could  be  applicable  in  Ukraine  for  road 
transport.  According to stakeholders, Ukraine appears to have a sizable international 
long-haul traffic (export/imports  and transit) that could merit the use of LNG as truck 
fuel.   

54 It is noted that according to UTG the planned Poland  – Ukraine pipeline is not included in the 2020 – 
2029 TYNDP of Ukraine.  

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  Gas-to-other fuels competition could  also have some  applicability in sea transport in 
Ukraine.  A large number of passenger and cargo ships regularly operate in Ukrainian 
waterways,  especially  Dnieper  and  Black  Sea  ports.  Switching  fuel  to  LNG  would 
nevertheless  involve  significant  costs,  and  therefore  compliance  with  international 
treaties  regarding  emissions,  such  as  IMO  regulations,  would  be  important  in 
influencing whether vessels convert to LNG as a cleaner fuel. Given that the Black Sea 
is  not  an  Emission  Control  Area  for  the  IMO,  the  requirement  to  reduce  sulphur 
emissions from the current 3.5% to 0.5% sulphur, as of 1/1/2020, can be  addressed 
by  shipowners  through  other  means  (scrubbers,  MGO  with  reduced  sulphur  etc.) 
instead of converting ships to use LNG (or order new ones running on LNG).  Potential 
LNG demand could therefore arise in case of newer vessels that operate internation al 
routes and not limited to Black Sea transport, as well as smaller vessels operating in 
inland waterways, especially the Dnipro and Dunay rivers.   

  LNG virtual pipelines could also be an applicable option for supplying gas distribution 
customers  in  Ukraine,  instead  of  expensive  replacements  of  old  gas  distribution 
pipelines.   The Ukrainian gas network is well developed, and most towns are gasified. 
There are nevertheless cases of very old gas distribution sections that can be replaced 
by LNG virtual pipelines, instead of heavily investing in rehabilitation.   

  LNG  virtual  pipelines could  also have  some applicability  in  supplying remote/off -grid 
customers  in  Ukraine.  Most  consumers  in  agriculture  and  mining  are  already 
connected to the gas network, but LNG could have some potential as  backup fuel or 
for fuelling heavy work tractors’ in mining.  Ukraine also has some remote  gas fields 
currently not connected to the network, and whose connection would involve significant 
difficulties and/or costly investments.  

  Liquefaction facilities can be used to develop remote gas fields. Virtual LNG pipelines, 
with  the  use  of  mini  liquefaction  facilities  to  transform  natural  gas  into  LNG  and  the 
transport it to end customers e.g. filling stations etc. can be used to  develop such gas 
fields.  According  to  JSC  Ukrgasvydobuvannya  (main  gas  production  facilities  of 
Naftogas Group), studies have been launched to assess such potential. 

  Use  of  LNG  as  locomotive  fuel  could  also  be  applicable.  The  Ukrainian  Railway 
Company (Ukrzaliznytsa) is currently using diesel as main locomotive fuel (327.1 mil. 
tonnes in 201855), that could potentially be substituted by LNG. 

Based on the above analysis, the applicable LNG market development options for Ukraine, for 
gas-to-gas and gas-to-other fuels competition, are presented in Table 33. Regasified LNG can be 
sourced  from  neighbouring  EU  terminals  (Świnoujście,  Klaipeda,  Revythoussa,  Krk)  and 
potentially the development of an in-country LNG receiving terminal, constructed near Odessa. 
Development  of  the  latter  is subject to  either  Ukraine  agreeing  with Turkey  for the  passage of 
LNG through the Bosporus Straits, or, in the long-term, LNG of Caspian origin being available to 

55 Source: Ukrainian Ministry of Infrastructure 

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be  produced  and  exported  from  a  liquefaction  terminal  in  Georgia  (as  currently  there  are  no 
available supplies of Caspian gas to feed such a potential infrastructure). 

LNG  for  gas-to-other  fuels  competition  can  be  sourced  from  the  nearby  EU  terminals 
(Świnoujście, Klaipeda), the in-country LNG terminal or a mini liquefaction facility connected to 
the Ukrainian transmission system. It should be noted that gas-to-other fuels options cannot be 
considered as drivers for the development of the Ukrainian LNG terminal, but can benefit in case 
such infrastructure goes ahead. 

Table 33: Applicable options for LNG market development in Ukraine 

Options for LNG market development 

Gas-to-Gas 
Competition 

Gas-to-Other 
Fuels Competition 

Regasified LNG sourced from 
neighbouring EU terminals 
Regasified LNG sourced from an in-
country LNG receiving terminal in the 
Black Sea 
Regasified LNG sourced from a potential 
liquefaction terminal in Georgia and an in-
country receiving terminal 

LNG as engine fuel for long-haul trucks 
LNG as engine fuel for ships operating in 
the Black Sea and Ukrainian waterways 
LNG supplies to off-grid customers, 
especially in agriculture, construction, and 
mining  
LNG virtual pipelines in distribution 
systems instead of large rehabilitation 
investments in distribution systems 
LNG virtual pipelines to connect remote 
gas fields with off-grid customers 
LNG as engine fuel for locomotives 

Sources of supply 
Świnoujście, Klaipeda, Revythoussa, 
Krk receiving terminals56 

Potential in-country receiving 
terminal 

Potential liquefaction terminal in 
Georgia 

  LNG truck loading in Świnoujście 

and/or Klaipeda terminals 

  In-country receiving terminal 

  In-country mini liquefaction facility 

8.2 Assessment of viability of applicable LNG market options 
8.2.1 Supply of regasified LNG from neighbouring EU terminals 
This LNG market development option can be considered as potentially viable for Ukraine in case 
LNG  can  arrive  to  the  Ukrainian  market  from  the  neighbouring  EU  LNG  terminals  at  a  price 
competitive  to  that  of  the  existing  gas  supply  sources,  taking  into  consideration  all  relevant 
transportation costs.  

To  estimate  the  competitiveness  of  LNG,  netback  analysis  was  performed,  starting  from  the 
wholesale gas price in Ukraine, up to each examined receiving terminal, taking into consideration 
in-country transportation costs, pancaking of the in-between cross-border tariffs and charges for 

56 Other  potential  supply  options  include  the  Marmara  Ereglisi  terminal  in  Turkey  and  the  planned  Alexandroupolis 
FSRU in Greece and Gdansk FSRU in Poland. The netback analysis of these options would wield similar results with 
the examined terminals. 

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the use of the receiving terminal. The detailed approach and calculations are described in Annex 
2.1. 

The average price of gas import from EU, including the entry tariff to enter the Ukrainian market, 
is  used  as  the  starting  point.  As  import  prices  are  fluctuating  considerably,  we  examine  3 
scenarios for the average level of import prices in Ukraine, corresponding to the average (241 
EUR/1000 m3), average for winter season (257 EUR/1000 m3) and minimum (198 EUR/1000 m3) 
price for the period Q1 2017 – Q2 201957. 

The  netback  analysis  performed  at  the  winter  average  price,  for  each  examined  route,  is 
presented in the Figures below. 

Figure 21: Netback analysis at winter average price for route Poland->Ukraine 

Figure 22: Netback analysis at winter average price for route Lithuania->Poland->Ukraine 

Figure 23: Netback analysis at winter average price for route Greece->Bulgaria->Romania->Ukraine 

Figure 24: Netback analysis at winter average price for route Croatia->Hungary->Ukraine 

Figure 25 presents the results of the netback analysis for all assumed wholesale prices, and all 
examined routes to Ukraine. 

57 Source: NEURC, “Monitoring results for functioning of the gas market”, Q2 2019 

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Figure 25: Netback analysis results for routes of regasified LNG from EU terminals to Ukraine, all 
examined wholesale prices  

The results of the analysis show that under the examined assumptions and market conditions, 
regasified LNG sourced from EU terminals seems to be marginally competitive in the Ukrainian 
market  in  case  the  prices  of  EU  imported  gas  exceed  the  winter  average  of  the  past  years. 
Consequently,  this  LNG market  development  option  could  be  considered as potentially  viable, 
provided that the spread between LNG price at the terminals and prices of imported supplies from 
current sources is at least in the order of 40 – 50 EUR/1000 m3 (depending on the route).   

This option does not provide additional benefits of route diversification, as the supply of regasified 
LNG from the terminals in the region would not open up new supply routes.   

8.2.2 Supply of regasified LNG from in-country terminal 
This LNG market development option can be considered as potentially viable for Ukraine in case 
LNG  can  arrive  at  a  Ukrainian  receiving  terminal  through  the  Bosporus  Straits  at  a  price 
competitive  to  that  of  the  existing  gas  supply  sources  for  the  Ukrainian  market,  taking  into 
consideration all relevant transportation costs. Agreement with Turkey for passing of LNG vessels 
through the Bosporus Straits in an on/off precondition for this option to be developed. 

The Ukrainian terminal is planned to be located near Odessa. As there are no up-to-date studies 
concerning  the  LNG  terminal  in  Ukraine58,  assumptions  are  made  concerning  the  size  of  the 
terminals.  In  Ukraine,  the  analysis  within  the  frame  of  this  Study  is  carried  out  assuming  the 
development of an FSRU with maximum send-out capacity of 5 bcm/yr.   

Netback analysis was performed, starting from the gas price of imported gas in Ukraine, up to the 
terminal, taking into consideration in-country transportation costs and charges for the use of the 
terminal. The detailed approach and calculations are described in Annex 2.2.  

58 Studies for the development of an LNG terminal near Odessa (Phase 1 FSRU with 5 bcm/yr capacity and Phase 2 
on-shore terminal with 10 bcm/yr capacity) were prepared in 2013, with very different supply & demand conditions in 
the Ukrainian market than the existing ones. 

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The same price scenarios as in Section 8.2.1 are examined. As the terminal charges depend on 
its utilization rate, we examine 3 scenarios of low (30%), medium (50%) and high (70%) utilization. 

Figure 26 presents the results of the netback analysis for all assumed prices and utilization rates.  

Figure  26:  Netback  analysis  results  for  supplies  of  regasified  LNG  from  in-country  terminal  in 
Ukraine, all examined import prices and utilization rates 

LNG price in the Black Sea can be expected to be higher than that of the Mediterranean, due to 
the additional transport costs and fees for crossing through the Bosporus Straits. With LNG import 
price at the Greek Revythoussa terminal 210 EUR/1000m3 in Q2 201959, it is assumed that the 
corresponding price in the Black Sea will be at least 5% higher. 

The  results  of  the  netback  analysis  show  that,  under  the  examined  assumptions  and  market 
conditions, an LNG receiving terminal in Ukraine can be economically viable only in case there is 
a price differential of at least 25 – 30 EUR/1000 m3 between LNG supplies and imports from EU, 
together with a high utilization of the terminal. Taking into consideration that EU import prices are 
driven by the prices at the European gas hubs, which in turn are affected by the global LNG price 
trends, attractive prices of LNG for the terminal could be ensured through long-term contracts that 
also secure a significant utilization of the infrastructure.  

Economic  analysis  for  this  LNG  option  was  conducted,  to  assess  whether  the  benefits  of 
developing an LNG terminal to the economy and society can outweigh its costs, even if the price 
of imported gas from the EU does not have a significant price differential from LNG. The analysis 
covers the scenarios of importing piped gas at the minimum and average prices of the past two 
years. The detailed approach and calculations are described in Annex 4.1. 

Figure  27  presents  the  calculated  economic  net  present  value  for  each  the  examined  price 
scenarios and corresponding utilization rates.  

59 Source: DG Energy, “Gas Market Report Q2 2019” 

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Figure  27:  ENPV  results  for  supplies  of  regasified  LNG  from  in-country  terminal  in  Ukraine,  all 
examined import prices and utilization rates 

The  economic  analysis  results  show  that  development  of  an  LNG  terminal  in  Ukraine  is 
economically viable in case LNG can be available at prices lower than those of gas imported from 
EU  suppliers,  which  result  in  both  enhancing  security  of  supply  in  Ukraine  and  Moldova,  and 
reducing gas prices in the market. The use of the terminal only for security of supply purposes (in 
case piped gas prices remain at low levels) does not lead to positive results, as the impact of a 
potential short-term disruption of Russian transit can be mitigated with indigenous production and 
storage, and may lead to only a small part of demand to be curtailed (Figure 28). 

Figure 28: Present value of economic costs and benefits of in-country terminal in Ukraine 

(a) Minimum import price (only SoS) 

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(b) Average import price (30% utilization) 

The  impact  of  the  LNG  terminal  in  Ukraine  has  also  been  examined  using  the  quantitative 
indicators, presented in Table 34. Development of the terminal can eliminate the potential impact 
of a large infrastructure disruption. Diversification of routes is also enhanced, although Ukraine 
already  is  well  connected  with  neighbouring  countries  and receives  gas supplies  from  various 
counterparts. The detailed approach and calculations of the indicators is provided in Annex 4.4. 

Table 34: Quantitative indicators for in-country terminal in Ukraine 

W/o terminal 

With terminal 

Impact 

N-1 indicator 

Import route 
diversification 
Demand curtailment 

97.3% 

4,229 

- 

104.% 

3,247 

- 

Increase of system resilience to a 
large infrastructure disruption 
Further increase of diversification of 
routes 
No curtailed demand 

Based on the above analysis, the development of an in-country LNG receiving terminal in Ukraine 
can be considered as a potentially viable LNG option, in case LNG can be supplied at lower prices 
than existing sources, and high (over 50%) utilization of the terminal can be ensured, e.g. through 
long-term terminal use agreements. It is noted that this LNG market development option can only 
be realized in case Ukraine and Turkey conclude an agreement for the passage of LNG vessels 
through the Bosporus Straits. 

8.2.3 Supply of regasified LNG from Georgian liquefaction terminal 
This LNG market development option can be considered as potentially viable for Ukraine in case 
LNG can arrive at a Ukrainian receiving terminal from a liquefaction and LNG export terminal in 
Georgia, at a price competitive to that of the existing gas supply sources for the Ukrainian market, 
taking into consideration all relevant transportation costs. This option can only be developed in 
the  long-term,  provided sufficient  gas  supplies  of  Caspian  origin  are  secured for  the  Georgian 
terminal, for liquefaction and export. 

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The liquefaction terminal in Georgia is assumed to have an LNG production capacity of 2 bcm/yr, 
and a utilization rate of 90% (with LNG supplied to Eastern Partners and EU countries). For the 
Ukrainian receiving terminal, the assumptions described in Section 8.2.2 above, concerning the 
terminal and market wholesale prices are applied. 

Netback analysis was performed, starting from the gas price of imported gas in Ukraine, up to the 
Georgian gas market, taking into consideration in-country transportation costs, charges for the 
use  of  the  receiving  terminal  in  Ukraine,  costs  for  transportation  of  LNG  and  liquefaction  in 
Georgia. The detailed approach and calculations are described in Annex 2.3.  

Figure 29 presents the results of the netback analysis for the assumed import prices in Ukraine 
and terminal utilization rates.  

Figure 29: Netback analysis results for supply of Ukrainian LNG terminal from Georgian liquefaction 
terminal, all examined import prices and utilization rates 

The investment cost for the 2 bcm/yr configuration of the AGRI Pipeline60 is applied as a basis. 
However, as the costs associated with the development of the facility are a key cost element in 
the  analysis,  and  these  may  have  changed,  due  to  the  introduction  of  new  technologies  (e.g. 
FLNG  terminal),  sensitivity  analysis  was  performed,  assessing  also  80%  and  60%  of  the 
investment  costs.  Figure  30  presents  the  results  of  the  sensitivity  analysis  for  the  scenario  of 
winter average import price in Ukraine, and 70% utilization of the Ukrainian receiving terminal. 

60 GNERC, “Case Study: Georgia’s Growing Gas Market”, 2018 

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Figure 30: Netback analysis results for supply of Ukrainian LNG terminal from Georgian liquefaction 
terminal, sensitivity analysis on liquefaction terminal investment cost 

The  results  of  the  analysis  show  that  in  all  the  examined  scenarios,  the  supply  of  LNG  at  a 
Ukrainian receiving terminal from a liquefaction terminal in Georgia can be competitive to existing 
imports only in case the price of Caspian gas supplied to the liquefaction terminal is significantly 
lower than current import prices of Azeri gas in Georgia. 

Economic  analysis  for  this  LNG  option  was  conducted,  to  assess  whether  the  benefits  of 
developing  an  LNG  terminal  to  the  economy  and  society  can  outweigh  its  costs.  The  analysis 
covers the case having the highest netback price (winter average price), examining two scenarios 
of Caspian gas export prices (current level of Azeri gas supply to Georgia and low export price). 
Sensitivity  analysis  on  the  investment  costs  of  the  liquefaction  is  also  applied.  The  detailed 
approach and calculations are described in Annex 4.3. 

The economic analysis results show that the main benefit of the LNG option is the reduction of 
energy costs. Under the examined scenarios, the option is viable in case LNG can be delivered 
in the Ukrainian terminal at a low price, and a high utilization rate is secured at the terminal. The 
use of the terminal only for enhancing security of supply in Ukraine and Moldova does not lead to 
positive  results,  as  the  impact  of  a  potential  short-term  disruption  of  Russian  transit  can  be 
mitigated with indigenous production and storage, and may lead to only a small part of demand 
to be curtailed (Figure 31). 

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Figure 31: Present value of economic costs and benefits of in-country terminal in Ukraine 

(a) Low export price of Caspian gas (100% of liquefaction costs) 

(b) Low export price of Caspian gas (60% of liquefaction costs) 

Based  on  the  above  analysis,  the  development  of  a  liquefaction  and  LNG  export  terminal  in 
Georgia, supplying an LNG receiving terminal in Ukraine can only be considered as a potentially 
viable LNG option, in case supply prices of Caspian gas are low, and a high (over 50%) utilization 
of  the  Ukrainian  receiving  terminal  can  be  ensured,  e.g.  through  long-term  terminal  use 
agreements. As the results are sensitive on the costs of liquefaction, further analysis of this option 
requires detailed  examination  of  the  investment needs for the  liquefaction  terminal, taking  into 
consideration current liquefaction technologies and infrastructure. 

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8.2.4 Supply  of  LNG  via  trucks  to  consumers  connected  to  the 
transmission system  
This LNG market development option can be considered as potentially viable for Ukraine in case 
the price of regasified LNG injected to the Ukrainian transmission system through a central LNG 
receiving  terminal,  which  is  supplied  with  LNG  trucks  from  the  Świnoujście  and  Klaipeda 
terminals, can be competitive to that of the existing gas supply sources, taking into consideration 
all relevant transportation costs.  

For the purpose of the analysis, we assume that the size of the regasification terminal and the 
number of LNG trucks used will cover annual demand of 500 mcm in Ukraine that is close to the 
maximum nominal capacity of the Klaipeda reloading station (100 m3 LNG/h). 

Netback  analysis  was  performed,  starting  from  the  import  gas  price  in  Ukraine,  up  to  each 
examined receiving terminal, taking into consideration in-country transportation costs, charges for 
the use of the LNG receiving terminal, costs of transporting LNG with trucks, and truck loading at 
the neighbouring terminals. The detailed approach and calculations are described in Annex 2.4. 

The same price scenarios as in Section 8.2.1 are examined. 

Figure 32 presents the results of the netback analysis for supply of LNG from the two examined 
terminals, and all assumed import prices.  

Figure  32:  Netback  analysis  results  for  supplies  of  LNG  to  Ukraine  via  trucks  to  transmission 
consumers, all examined import prices 

The results of the analysis show that, under the examined assumptions and market conditions, 
the use of LNG trucks as a means to supply LNG to the Ukrainian market, in competition to piped 
gas for consumers connected to the transmission system, is not commercially viable.  

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It  is  noted  that  the  potential  use  of  block  trains as  an  LNG  transportation  modality  could  yield 
different  results,  as  much  larger  volumes  can  be  transported  per  shipment 61,  and  therefore 
transportation costs can be lower. However, this option cannot be analysed in detail, as it has not 
been widely applied, and unit cost benchmarks are not available. Once the planned train loading 
facility in the Świnoujście terminal becomes operational, the relevant costs can be assessed. 

8.2.5 Use of LNG as engine fuel for trucks 
This LNG market development option can be considered as potentially viable for Ukraine in case 
the LNG price at the filling station is competitive to that of diesel, taking into consideration the 
efficiency gains of LNG engines, as well as all costs associated with the LNG supply chain.  

The  available  information  on  the  traffic  of  long-haul  trucks  (local  and  transit)  in  Ukraine  is  not 
sufficiently detailed to allow reasonable assumptions to estimate the market size of LNG as fuel 
for trucks.  For this  reason,  instead  of  performing a  netback  analysis  to  estimate the maximum 
price of LNG to be competitive to diesel, we estimate the LNG market size (number of LNG-fuelled 
trucks and annual LNG volumes consumed) required for prices of LNG and diesel to be on par, 
under different scenarios of LNG/natural gas prices at the beginning of the supply chain. 

The potential LNG supply sources examined for Ukraine include the LNG terminals in Świnoujście 
and  Klaipeda,  an  in-country  LNG  receiving  terminal  and  a  mini  liquefaction  facility.  For  each 
source,  a  base  price  and  positive/negative  sensitivities,  as  displayed  in  Table  35,  have  been 
assessed.   

Table 35: Examined prices of LNG/natural gas at the source for Ukraine 

Terminal 

Świnoujście LNG terminal26 
Klaipeda LNG terminal27 
Ukraine LNG terminal7 
In-country mini liquefaction facility62 

Assumed price at terminal (EUR/1000m3) 

Base price 
200 
200 
220 
254 

+25% 
250 
250 
275 
318 

+50% 
300 
300 
330 
381 

-15% 
170 
170 
187 
216 

-25% 
150 
150 
165 
190 

The analysis has been carried out for long-haul trucks retrofitted to use LNG, traveling 91,000 km 
per annum. The costs for development of a new filling station for LNG is considered (development 
of a new L-CNG station or upgrade of an existing CNG station would result in lower costs). The 
competing price of diesel has been assumed to be at the current market level, of 0.76 EUR/lt63. 
The detailed approach and calculations are presented in Annex 3.1.   

Figure 33 presents the minimum number of LNG-fired trucks that have to operate in Ukraine, and 
the minimum LNG volumes to be supplied annually, for the market to be developed, in case the 
base price applies at the LNG source.  

61 A block train of 20 tank wagons can transport 2,220 m3 of LNG (source: VTG, “Innovation for the track: Breaking new 
ground in LNG supply”, 2017) 
62 Average  wholesale  price  for  September  2018  –  September  2019  (Source:  Ukrainian  Energy  Exchange),  plus 
transportation tariff (Source: UTG) 
63 Source: https://index.minfin.com.ua/ua/markets/fuel/dt/ (accessed 1/11/2019) 

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Figure  33:  Minimum  number  of  LNG-fired  trucks  for  market  development  in  Ukraine  and 
corresponding annual LNG market size, under base price 

(a) Minimum number of LNG-fired trucks 

(b) Minimum LNG market size 

The minimum number of LNG-fired trucks for the Ukrainian case, for all price scenarios and LNG 
supply variants are presented in Figure 34. 

Figure 34: Minimum number of LNG-fired trucks in Ukraine for all price sensitivities 

The results of the analysis show that use of LNG in Ukrainian road transport, under the examined 
assumptions, can be competitive to diesel with a market of less than 100 LNG-fired trucks, even 
in case LNG import prices increase, for supplies from the neighbouring terminals in Poland and 
Lithuania. The  sourcing of  LNG from  an  in-country  receiving  terminal  could also be  an  option, 
provided that an agreement with Turkey for the Bosporus Straits is secured, and the terminal is 
developed. Supplies from a mini liquefaction facility would require a considerably larger market, 
at least around 250 trucks for the base price scenario. 

As Ukraine appears to have a sizable international long-haul traffic (export/imports and transit), a 
market for LNG in road transport of 100 or more trucks could potentially develop. Consequently, 
use of LNG as engine fuel for trucks can be considered as a potentially viable option for Ukraine. 
It is noted that in order to better size the size of the market, and its attractiveness, analysis of 

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detailed  data  on the  operation  of  long-haul  trucks  (such  as  number  of  local  and  transit  trucks, 
destinations and distances covered) in Ukraine would be required.  

Economic analysis was performed for the identified minimum required LNG market, to estimate 
the extent to which economic benefits for using LNG as engine fuel (energy cost reduction for end 
consumers, impact on GHG emissions) outweigh the costs for developing the option. The analysis 
shows that the reduction of GHG emissions has a positive impact (Figure 35).  

Figure 35: Present value of economic costs and benefits for use of LNG as engine fuel for trucks in 
Ukraine 

8.2.6 Use of LNG as engine fuel for ships 
Implementation of IMO rules setting the limit the ships’ sulphur emissions from 3.5% to 0.5% as 
of  1/1/2020  in  the  Black  Sea  leads  ship  owners  to  take  measures  to  meet  this  obligation. 
Internationally,  for  ships  currently  operating  in  the  sea  areas  outside  Emission  Control  Areas 
(ECAs), the use of scrubbers or low sulphur fuel oil seems to be the preferred solution compared 
to switching to LNG, as the retrofitting cost has been considered higher than that of alternative 
solutions64. The use of LNG can be more attractive in the case of newbuilds, provided that the 
price differential between LNG and the existing bunkering fuels is sufficient to cover the additional 
cost of an LNG-fuelled ship, and that bunkering of LNG is possible at ports or an LNG terminal in 
Ukraine.    

The attractiveness of this LNG option differs for each individual case of ship, as it depends on a 
number of factors, including the vessel’s size and type, age, service area, fuel used, refuelling 
pattern,  prices  of  competing  fuels,  etc.  For  this  reason,  a  case-by-case  analysis  would  be 
required, to examine for which ships use of LNG would be competitive. In this Study we provide 
an indicative example, concerning a newbuild 50,000 MT PANAMAX type vessel operating in the 
Black Sea, with LNG and MGO as competing fuels and bunkering at an LNG terminal in Ukraine. 

64 See analysis in Oxford Institute for Energy Studies, “LNG Supply Chains and the Development of LNG as a Shipping 
Fuel in Northern Europe”, 2019 

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The detailed approach and calculations are described in Annex 3.4. The results of the analysis 
show that for this case study the maximum supply price of LNG at the terminal is 325 EUR/1000 
m3.  Under  the  examined  assumptions,  LNG  can  be  considered  as  competitive,  in  case  LNG 
supply prices remain at the existing levels.  

Consequently,  the  use  of  LNG  for  ships  is  a  market  development  option  that  merits  further 
investigation, analysing the financial viability and potential LNG penetration specifically with the 
specific characteristics of the ships operating in Ukrainian ports.  

8.2.7 Supply of LNG to off-grid consumers 
This LNG market development option can be considered as potentially viable for Ukraine in case 
the natural gas price at the end consumer is competitive to that of the current fuel (e.g. diesel or 
LPG), any fuel efficiency gains, as well as taking into consideration all costs associated with the 
LNG supply chain.  

Although  in  Ukraine  the  transmission  system  is  well  expanded,  and  most  consumers  with 
significant energy demand are already connected, there are some individual cases of consumers 
(mainly small to medium agriculture, construction or mining sites) that are off-grid. Details on the 
number, size and characteristics of these consumers were not made available to the Consultant. 
For this reason, we examined an indicative case study for an agriculture site in the southern part 
of Ukraine that cannot be connected to the transmission system, due to the lack of gas pressure 
reduction  station  capacity  (the  case  study  is  based  on  actual  information  provided  by  an 
agriculture company).  

The potential LNG supply sources examined for Ukraine include the LNG terminals in Świnoujście 
and Klaipeda, an in-country LNG receiving terminal and a mini liquefaction facility. 

To estimate the competitiveness of LNG, netback analysis was performed, starting from the price 
of  competing  fuel  at  the  consumer  (LPG),  up  to  each  examined  receiving  terminal,  taking  into 
consideration gas efficiency compared to LPG, regasification costs, LNG transportation and truck 
loading costs. The detailed approach and calculations are described in Annex 3.3.  

Figure 36 presents the results of the netback analysis for each of the LNG sources examined. 

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Figure 36: Netback analysis results for supplies of LNG to off-grid consumers in Ukraine65 

Under the assumptions of the examined case study, supplies of LNG from receiving terminals can 
be  competitive  to  LPG.  Consequently,  this  LNG  market  development  option  is  considered  as 
potentially  viable,  at  least  for  some  of  the  off-grid  consumers  in  Ukraine.  Nevertheless,  each 
particular  off-grid  consumer  should  be  examined  individually,  as  the  parameters  affecting  the 
analysis  (e.g.  distance  from  the  terminal,  consumption  profile,  type  of  fuel,  size  of  required 
regasification terminal).  

Figure 37: Present value of economic costs and benefits for the supply of LNG to off-grid consumers 
in Ukraine 

An  economic  analysis  was  also  performed  for  the  supply  of  LNG  to  the  examined  off-grid 
agriculture site, to estimate the extent to which economic benefits (energy cost reduction for end 
consumers,  impact  on  GHG  emissions)  outweigh  the  costs  for  developing  this  option.  The 
analysis, for the particular case examined, shows that the largest benefit is the reduction of energy 
costs, while GHG emissions also have had a slight positive impact (Figure 37).  

65 Values for LNG supplies from a mini liquefaction facility are negative, and therefore not depicted 

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8.2.8 Use of LNG Virtual Pipelines in old distribution systems 
In several distribution systems of Ukraine, there are very old medium pressure pipeline sections, 
which  are  in  need  of  replacement,  supplying  areas  with  very  limited  number  of  consumers. 
Indicative cases  include a  9.5 km  pipeline  serving  demand  of  41,000 m3/yr  or  a  4 km  pipeline 
supplying  53,500  m3/yr.  Replacement  of  such  infrastructure  would  result  in  increases  of  the 
distribution tariff. 

The development of LNG virtual pipelines to supply such areas, instead of proceeding to pipeline 
replacement was examined as an alternative. However, taking into consideration that the cost of 
pipeline replacement amounts to around 22,000 EUR/km, the costs for the LNG supply would be 
much  higher,  as  demand  would  remain  the  same.  For  example,  replacing  a pipeline  of  10 km 
would cost around 220,000 EUR, while the cost of just a liquefaction facility would exceed 7 mil. 
EUR.     

Therefore, this option is considered as non-viable. 

8.2.9 Use of LNG Virtual Pipelines to develop remote gas fields 
This LNG market development option can be considered as potentially viable for Ukraine in case 
the liquefaction of gas produced at remote gas field, and transportation of LNG to off-grid areas 
can be price competitive to the existing fuels used by the targeted consumers. 

Data on Ukraine’s remote gas fields, required to analyse this option further were not available, 
consequently netback and economic analysis was not conducted within the frame of this Study.  

Key factors that have to be taken into consideration to assess the financial viability of the LNG 
option include the size field’s reserves and production capacity, that would enable sizing of the 
liquefaction facility, cost of gas production, proximity to potential consumers and size of targeted 
consumption. The cost of LNG delivered to the consumers should be competitive to the equivalent 
price of the dominant competing fuel, taking into consideration any additional costs and efficiency 
gains incurred due to the use of natural gas. 

The examination of each remote gas field should be carried out separately, as the characteristics 
and location of each field are unique.  

8.2.10 Use of LNG as engine fuel for locomotives of Ukrzaliznytsa 
This LNG market development option can be considered as potentially viable for Ukraine in case 
the LNG price is competitive to that of diesel, taking into consideration the costs for retrofitting the 
locomotives, and building the necessary infrastructure for LNG supply. 

An indicative cost for retrofitting a locomotive amounts to around 1.3 mil. EUR (550,000 EUR for 
the engine, and an additional cost of 750,000 EUR for a fuel tender that carries the LNG tank66) 

66 Source: Natural Resources Canada (NRCAN), “Economic and Environmental Benefits of Natural Gas for 
the Rail Sector”, March 2017 

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for a dual fuel (LNG/diesel) engine. Additional investments are required to install at selected rail 
depots, facilities for LNG unloading, storage and locomotive refuelling. Depending on the location 
of the depot, LNG could be supplied either via trucks (from LNG terminals) or via using a small-
scale  liquefaction  facility  within  the  depot  (in  case  a  transmission  pipeline  is  in  its  proximity). 
Benchmark costs for small scale LNG and liquefaction facilities are presented in Annex 6. 

The significant consumption of diesel in the Ukrainian rail sector (around 330 mil. tonnes in 2018) 
could create the conditions for switching to LNG. To assess the viability of the option, a detailed 
analysis should be carried out, identifying the number of locomotives to be retrofitted or replaced, 
the optimal locations for developing LNG refuelling facilities, and assessing whether all costs for 
developing the LNG supply chain can be covered from the LNG-diesel price differential. 

8.3 Prerequisites  and  key  success  factors  for  potentially  viable 
LNG market options 
8.3.1 Supply of regasified LNG 
The potentially viable options for supplying regasified LNG to the Ukrainian market are either via 
pipelines from existing EU terminals or by developing a new in-country terminal in Ukraine. The 
prerequisites and key success factors for each of the two options are described separately in the 
following Sections 8.3.1.1 and 8.3.1.2.  

Regardless of the options through which regasified LNG arrives to Ukraine, there are a number 
of factors that relate to the impact of LNG in enhancing competition in the Ukrainian gas market. 
These are described in Section 8.3.1.3.  

8.3.1.1 Supply of regasified LNG from neighbouring EU terminals 

Table 36 describes the key prerequisites for effective implementation of the option of supplying 
regasified LNG to Ukraine from the existing EU terminals. A critical/on-off prerequisite is the price 
competitiveness of regasified LNG at the Ukrainian border. There are also prerequisites related 
to the absence of regulatory or technical constraints for the supply of regasified LNG from the 
source terminal up to the Ukrainian market. 

Table 36: Prerequisites for supplying LNG from EU terminals 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Price of regasified LNG 
at Ukrainian border 
competitive to the 
existing gas supply 
sources of the Ukrainian 
market (as discussed in 
Section 8.2.1) 

Critical – on/off 
criterion for the 
viability of the option 

Uncertain 

LNG source prices 
are determined in 
accordance with 
international demand 
and supply conditions. 
Gas import prices in 
Ukraine are market 
based. It is the 
suppliers’ decision 

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Legal & Regulatory 
1  Absence of regulatory 
barriers for access to 
transportation 
infrastructure for the 
regasified LNG 

Infrastructure 
1  Absence of capacity 
constraints to import 
regasified LNG 

whether to import 
LNG    

Under the control of 
Ukraine as well as all 
other countries along 
the routes 

Under the control of 
Ukraine as well as all 
other countries along 
the routes 

Low 

Low 

Factors that could be conducive to the development of this option include: 

  Securing long-term supplies of LNG at a stable price, to avoid spot price fluctuations. 
This nevertheless has risks in case spot prices move lower than the contracted price. 
Additionally, this would require contracting large quantities. 

  Lifting barriers for LNG suppliers to utilize Ukrainian storage. Access to storage would 
enable suppliers to take advantage of any low-priced LNG spot supply opportunities. 

8.3.1.2 Supply of regasified LNG from in-country terminal 

Table 37 describes the key prerequisites for effective implementation of the option of establishing 
an  in-country  LNG  import  terminal.  Critical/on-off  prerequisites  are  the  uninterrupted  supply  of 
LNG  to  the  terminal  i.e.  the  absence  of  any  constraints  for  LNG  vessels  to  pass  through  the 
Bosporus  straits,  and  the  existence  of  sufficient  interest  by  potential  users,  as  evidenced  by 
market tests. Another important prerequisite relates to the availability of financing for the terminal, 
from  State  or  private  funds.  The  necessary  changes  in  the  legal  and  regulatory  framework, 
including  permits  and  licenses,  are  also  detailed,  as  well  as  the  need  to  connect  to  the  gas 
transmission network. 

Table 37: Prerequisites for development of in-country LNG terminal 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Political 
1  Absence of any maritime 
or other constraints for 
LNG vessels to reach 
and supply the terminal   

Market 
1  Binding market tests 
confirming interest of 
suppliers to use terminal 
services before FID for 
the terminal is taken 

Critical - on/off 
condition, to ensure 
uninterrupted, prompt 
and adequate LNG 
supplies to the terminal 

Critical - on/off 
condition, to ensure 
there is secure and 
sufficient demand for 
the terminal’s services 
to make it viable. A 

High 

Under the control of 
Turkey. Negotiations 
need to be initiated 
by Ukraine  

Decision of 
suppliers 

Uncertain 

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successful market test 
requires suppliers to 
take a view on the 
competitiveness of LNG 
price vis-à-vis the 
Ukrainian gas import 
prices (as discussed in 
Section 8.2.2)    

To add the right to 
establish terminal and 
the applicable 
framework in the law 

To ensure that all 
authorisations and 
preconditions are 
secured 

Legislators and policy 
makers need to set the 
rules so as to ensure 
safety, efficiency, 
quality and 
environmental 
protection   

Legislators and policy 
makers need to set the 
rules so as to ensure 
safe, efficient and 
environmentally 
conducive terminal 
operation    
Legislators and 
regulators need to set 
the rules (in 
accordance with EC 
Acquis), and terminal to 
comply   

To ensure that the 
terminal can go ahead 
(FID) 

For the terminal to be 
able to send regasified 
LNG to the system, in 
accordance with pre-
defined rules 

Legal & Regulatory 
1 

(Amendment to) energy 
law to allow establishing 
of LNG terminal, 
including ownership, 
regulation, TPA 
provisions and pricing 
regulation 

2  Permits and licenses for 
LNG terminal, including 
prerequisite technical 
studies, environmental 
and social impact 
assessment study 

3  Regulations and 

standards for the siting, 
design, construction and 
installation of LNG 
terminal, including 
infrastructures (jetty and 
connections to 
transmission system)  

4  Regulations for the 
operation of LNG 
terminal  

5  Regulatory license and 

process for accreditation 
of the terminal 

Financing 
1  Securing adequate 
financing for the 
investment in the 
terminal  
Infrastructure 
1  Connection of terminal 
to the transmission 
network and agreement 
between terminal 
operator and TSO 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Decision of State 
and/or investors 

High 

Under the sole 
control of Ukraine 

Low 

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Table 38 outlines the key success factors for the implementation of the option of establishing an 
in-country LNG import terminal. These factors influence the speed of market development.  Some 
of the key success factors relate to the strength of the project promoter (access to finance etc.) 
and the existence of investment partners and experienced operator.  Other success factors relate 
to having a clear and effective strategy or the development of the terminal to avoid risks of delays 
and  cost-overruns  and  having  a  contractual  strategy/model  that  allocates  fairly  risks  between 
contractors and developer. A conducive legal framework in the country as well as State support 
to the venture is important. For the terminal sustainability as a business it is important to secure 
adequate customers, especially large off-takers, and to offer good service levels at a competitive 
price.  Finally, flexibility both in terms of terminal infrastructure and in terms of services, to changes 
in market conditions, enhances sustainability. 

Table 38: Key success factors for development of in-country LNG terminal 

Key success factors 

Rationale 

1  Strength (financial and otherwise) of the project 

promoter 

2  Bring-in strategic investment partners that can 

bring expertise to the venture and mitigate risks 

3  Bring-in experienced operator/management team 

4  Establishing an effective project delivery strategy 
for the terminal (for project teams, partners, 
contractors, consultants, stakeholder 
engagement, safety, financing, technical 
solutions, risk management, project control and 
monitoring etc.)  

5  Use contractual models that balance and align 

interests of terminal developers/operator (locking-
in key suppliers and reducing supply chain costs) 
and contractors/suppliers (having flexibility to deal 
with volatile commodity and service prices) 

Assurance for project completion and 
sustainability 
To ensure sustainability and mitigate 
business risks 
To ensure sustainability and mitigate 
business risks 
To ensure prompt and effective construction 

To ensure sustainability and mitigate 
business risks 

6  Host country has predictable and conducive legal, 

To avoid risks 

contractual and regulatory framework  

7  Competitive prices for the terminal’s services and 

To ensure sustainability  

good service levels 

8  Government is supportive in general for the 

To avoid delays and risks 

venture, and specifically ensures timely issuance 
of terminal permits and authorizations 

9  Existence of a market for LNG (regasifed and in 
liquid form) that can sustain the terminal’s 
operations.  

10  Dependence on one major off-taker or several off-

takers.   

11  Terminal operation flexibility to adjust in case 

market conditions change (e.g. developing new 
services, pricing for unbundled services as 
opposed to bundled, flexibility to add new 
infrastructures such as jetty, tanks, truck loading 
facilities etc.)  

To ensure sustainability 

One major off-taker is preferable to lenders, 
but also increases dependence compared to 
situation of a portfolio of off-takers 
To ensure adaptability and sustainability  

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8.3.1.3 Factors impacting competition in the Ukrainian gas market 

Regasified LNG is a new source of gas supply, as well as a new route, in the case of an in-country 
import terminal. It has the potential to enhance competition in the Ukrainian gas market, especially 
when the following factors apply:    

  Completing  the  implementation  of  the  obligations  stemming  from  the  Energy 
Community related to market operation and gas network codes that will enhance non-
discriminatory and transparent access of regasified LNG to the Ukrainian network and 
market. 

  Completing  the  liberalisation  of  gas  market  (e.g.  reassessing  extent  and  duration  of 
current PSOs to non-regulated customers, unbundling of gas distribution etc.), to open 
up competition to a larger share of the market. 

8.3.2 Use of LNG as engine fuel for trucks 
Table 39 describes the key prerequisites for effective implementation of the option of using LNG 
as engine fuel for trucks in Ukraine. The prerequisites concern the appropriate price differential 
between LNG and diesel to ensure viability, as well as the necessary changes in the legal and 
regulatory  framework,  or  introduction  of  new  legislation  and regulations,  including  permits  and 
licenses. For example, Ukraine has a Law on Dangerous Cargo Transportation and secondary 
regulations issued by the Ministry of Internal Affairs, and LNG is included. The prerequisites relate 
not  only  to import  and operation of  trucks,  but  extend to the supply  chain for  LNG  concerning 
trucks: filling stations, truck loading facilities at an in-country LNG terminal, in case this option is 
implemented  and  LNG  is  sourced  from  there,  liquefaction  plants  and  truck  loading  facilities  at 
these plants, in case LNG is sourced from piped gas in the country. The interest of sufficient truck 
owners to switch to LNG, and the attraction of investments to develop the necessary infrastructure 
(filling stations, liquefaction facilities) is also critical for the development of the market. 

It is noted that the prerequisites related to the import of LNG through an in-country terminal and 
the development of relevant import facilities in Ukraine are listed separately in Section 8.3.1. 

Table 39: Prerequisites for development of LNG as engine fuel for trucks 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and diesel (as discussed 
in Section 8.2.5)  

Critical – on/off 
condition, as 
switching to LNG 
requires an attractive 
price of LNG vis-à-vis 
diesel at the end use 

Uncertain 

LNG and diesel 
source prices are 
determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is 
sourced from an in-
country liquefaction 

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facility, in which the 
price is determined 
by gas import 
contracts)   
Decision of truck 
owners 

Medium 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

2 

Interest of a critical mass 
of truck owners to switch 
to LNG 

Legal & Regulatory 
1  Regulations and 

standards for the design, 
manufacturing and 
installation of the LNG 
fueled trucks and 
different components 
(e.g. pressure control 
regulator, LNG filling 
receptacle etc.) for 
approval of LNG 
vehicles import and 
operation67, 68 

2  Road regulations for 
circulation of LNG 
fuelled vehicles 

3  LNG and L-CNG filling 
stations permits and 
licences, notably building 
license, operation 
license, and business 
license69 

Viability of the option 
is dependent on 
having a minimum 
market size to justify 
investments  

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.  There are 
various European 
and international 
standards that could 
be incorporated in 
national legislation as 
the basis for granting 
approval. 
Need to ensure 
safety, by stipulating 
any restrictions in 
movement e.g. in 
cases of heavy traffic, 
adverse weather 
conditions affecting 
visibility and road 
conditions etc.  
Need to ensure the 
eligibility of the 
selected site for the 
station, compliance 
with operational 
obligations (e.g. 
opening hours, 
station throughput, 
safety obligations, 
and business 
registration of the 
entity.  The licenses 
require testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 

67 DG MOVE, LNG Blue Corridors, Vehicle Regulations - State of the Art, December 2013 
68 DG MOVE, LNG Blue Corridors, LNG stations Regulations -State of the art, December 2013 
69 DG MOVE, LNG Blue Corridors, Guidelines for set up & operation of stations, May 2015 

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4  LNG and L-CNG filling 
stations regulatory 
guidelines69 in relation to 
set-up and construction 
(e.g. distance, tank 
levels etc.), operation 
(e.g. guarantee sufficient 
product), and 
maintenance (planned 
maintenance work in a 
programmed schedule) 
of the station. 

5  Road safety regulations 
for trucks carrying LNG 
to the filling stations.   

6  Regulations governing 

TPA of LNG carrying 
trucks at LNG terminal 
(in case an in-country 
LNG terminal with truck 
loading facilities is 
developed) 

7  Regulations governing 

loading of LNG to trucks 
at LNG terminal facilities 
(in case an in-country 
LNG terminal with truck 
loading facilities is 
developed) 

8  Regulations governing 
pricing of LNG terminal 
truck loading facilities (in 
case there is an LNG 
terminal with truck 
loading facilities, and 

granted and after 
(inspection/checks for 
compliance)  
Need to ensure 
safety and efficiency 
of the station.  The 
regulations require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  
LNG transportation 
carries some 
potential hazards, 
linked to flammability 
as well as the impact 
of cryogenic fuel 
exposure or 
leakage.  There are 
standards that could 
be adopted (3 years 
ago, LNG and CNG 
were included in the 
ADR.   
Need to ensure 
transparent and non-
discriminatory access 
of truck operators to 
the truck loading 
facilities 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc.  
Need to have 
published tariffs for 
truck loading facility 
services at the 
terminal, that are 
non-discriminatory for 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

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there is price regulation 
for third party access to 
such facilities) 

9  Permits and licenses, 
including technical 
specifications, for truck 
loading facilities at LNG 
terminal (in case an in-
country LNG terminal 
with truck loading 
facilities is developed) 
10  Permits and licences, 
including technical 
specifications, for 
liquefaction facilities (in 
case LNG is sourced 
from the gas network 
and loaded on to trucks)  

11  Permitting process, 
including technical 
specifications, for truck 
loading at liquefaction 
facility  (in case there is 
a liquefaction facility)  

12 

(Amendment to) law to 
specify whether/which 
type of liquefaction 
facilities are regulated 
(TPA and pricing) 
13  Regulations governing 
TPA of LNG trucks at 
liquefaction facility (in 
case there is a regulated 
liquefaction facility) 

14  Regulations governing 

pricing of liquefaction 
facility (in case there is a 
regulated liquefaction 
facility) 

users, and 
regulations for the 
allowed costs in such 
tariffs 
Need to have permits 
and regulations 
specifying layout 
requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 
Need to have permits 
and regulations for 
site requirements, 
health and safety 
considerations, 
transportation 
infrastructure, 
availability of key 
utilities, air emissions 
and wastewater 
treatment. 
Need to have permits 
and regulations 
specifying layout  
requirements and 
operational aspects, 
to address safety 
issues including fire 
protection. 

Need to establish 
rules and procedures 
for how truck 
operators will use the 
truck loading 
facilities, including 
LNG truck approval 
procedure, LNG 
specifications, 
procedures for 
determining the LNG 
mass loaded etc. 
Need to have 
published tariffs for 
use of the 
liquefaction plant 
services, that are 
non-discriminatory for 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

Under the sole 
control of Ukraine 

Low 

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Infrastructure 
1 

Interest of investors to 
implement necessary 
infrastructure (filling 
stations, in-country 
liquefaction facility) 

users, and 
regulations for the 
allowed costs in such 
tariffs 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
trucks to be able to 
operate  

Decision of investors  Medium 

Table 40 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for trucks. These factors influence the speed of market development.  Some of the 
key success factors relate to the State providing support to catalyze investments in LNG trucks 
and filling stations. Others relate to having a regulatory framework that favors ‘cleaner’ LNG use 
in trucking and punishes more ‘dirty fuels’.  State can also regulate the level of subsidies in other 
fuels, to make LNG more competitive.  Other prerequisites relate to the role of State and State 
organizations  to  foster  changes  and  to  support  investors  (one-stop-shop).  Finally,  the  role  of 
information campaigns for consumers, users and investors is important to overcome resistance 
to change and to boost interest. 

Table 40: Key success factors for development of LNG as engine fuel for trucks 

Key success factors 

Rationale 

1  Conducive fiscal framework (low taxes, low import 
duties, availability of state grants and rebates) for 
the purchase of LNG fuelled trucks or the 
retrofitting of existing trucks to LNG.  

2  Setting and enforcing circulation restrictions for 
trucks that use older generation engines with 
higher emissions detrimental to the environment 
(e.g. Euro 4 fuels)  

3  Reduction of subsidies and favourite tax treatment 

of fuels competing with LNG, to make LNG more 
competitive and incentivise its use. 

4  Conducive fiscal framework (specific concession 

regimes, tax holidays, state grants70) conducive to 
investment in construction of new LNG filling 
stations, or for retrofitting petrol stations to include 
LNG, or for retrofitting CNG stations to offer also 
LNG (L-CNG). Also, state co-funding of LNG R&D 
activities 

5  Awareness and promotion campaigns for LNG. 

Having sufficient network of LNG stations is a 
major success factor. Incentivising private 
investment is one way to develop the market.   

Consumers should be educated as to the 
potential features and benefits of LNG in 
transport.  Investors should be informed on 
the opportunities available.  Such campaigns 

70 ‘Connecting Europe Facility’, for example, provides grant to co-finance investment in LNG filling stations in the EU 

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6  Having a ‘National champion’ e.g. the Ministry of 

Energy or a State Committee that includes gas 
company and other key stakeholders.  The role of 
the National champion would be to coordinate the 
set-up of the required legal and regulatory 
framework, develop and implement policy and 
incentives, to remove obstacles in for LNG market 
development and to act as one-stop-shop for 
investors. Its role would also include planning the 
number and location of LNG filling stations and 
facilities (possibly introducing limited concessions 
for infrastructure) so as to avoid stranded 
investments.    

can counter resistance to change and speed 
up interest. 
Many initiatives are slowed down by 
regulatory gaps or unclear legislation, lack of 
implementing administrative mechanisms 
and bureaucracy and lack of action.  Such 
problems are exacerbated due to lack of 
awareness and resistance to change or 
inertia.  For example, customs may not be 
familiar with rules and regulations for the new 
LNG vehicles and delay their clearance.   

8.3.3 Use of LNG as engine fuel for ships 
Table 41 describes the key prerequisites for effective implementation of the option of using LNG 
as engine fuel for ships. The prerequisites concern appropriate price differential between LNG 
and fuel oil to ensure viability, and the introduction of necessary regulations concerning LNG ships 
design  and  operation,  as  well  as  regulations  and  permits  concerning  bunkering  facilities.  The 
choice of ship owners to use LNG as fuel and the development of required infrastructure at ports 
is also critical for the development of the market. 

Table 41: Prerequisites for development of LNG as engine fuel for ships71 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Market 
1  Sufficient price 

differential between LNG 
and fuel oil (as 
discussed in Section 
8.2.6), for the vessels 
that are targeted for fuel 
switching  

Viability of the option 
is dependent on LNG 
being competitive to 
fuel oil for use in 
shipping, so that 
investments in fuel 
conversion for the 
particular vessels can 
be recovered 

2 

Interest of ship owners 
to retrofit or build new 
LNG-fueled vessels, 
based on technical 

There are alternative 
options to be applied 
by ship owners to 
reduce costs and 
emissions 

LNG and fuel oil 
source prices are 
determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is sourced 
from an in-country 
liquefaction facility, in 
which the price is 
determined by gas 
import contracts)   
Decision of ship 
owners 

Uncertain 

Medium to high 

71 In case of LNG supplied from liquefaction facilities to ports via trucks, the relevant points of Table 39 also apply. 

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feasibility and financial 
attractiveness 
Legal & Regulatory 
1  Codes and Regulations 
for the design of LNG 
ships, based on 
guidelines set by 
organisations such as 
the International 
Maritime Organisation 
(IMO), the Society of 
International Gas 
Tankers 
and Terminal Operators 
(SIGTTO), the Oil 
Companies International 
Marine Forum (OCIMF) 
and other ISO, 
European (EN) and 
National Fire Protection 
Association (NFPA) 
standards 

2  Codes and Regulations 
for the design and 
operation of LNG 
bunkering facilities, 
based on ISO guidelines 
(for systems and 
installations for supply of 
LNG as fuel to ships) as 
well as other 
international guidelines  
3  LNG bunkering facilities 
permits and licences  

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Under the sole control 
of Ukraine 

Low 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection.   

Under the sole control 
of Ukraine 

Low 

Under the sole control 
of Ukraine 

Low 

Need to ensure the 
suitability of the 
selected site for the 
facility, compliance 
with operational 
obligations (e.g. 
opening hours, station 
throughput, safety 
obligations) etc. The 
licenses require 
testing and 
acceptance 
processes and 
mechanisms at 
state/municipal level, 
before licences are 
granted and after 
(inspection/checks for 
compliance)  

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Infrastructure 
1 

Implementation of 
necessary infrastructure 
(LNG bunkering 
infrastructure at ports 
and/or waterways) 

The required 
infrastructure must be 
developed in time for 
the LNG-fuelled 
vessels to be able to 
operate  

Decision of State 
and/or private 
investors 

Medium 

Table 42 outlines the key success factors for the implementation of the option of using LNG as 
engine fuel for ships. These factors influence the speed of market development.  Some of the key 
success factors concern IMO regulations that influence the choice of LNG driven ships, especially 
newbuilds, vis-à-vis ships using other low emission fuels. Other prerequisites relate to having a 
legal  framework  conducive  to  investments  and  access  to  finance  for  the  large  investments 
needed.    Another  prerequisite  for  LNG  fuelled  ships  is  the  availability  of  adequate  bunkering 
infrastructure.   

Table 42: Key success factors for development of LNG as engine fuel for ships 

Key success factors 

Rationale 

2. 

1.  Reliability,  operating  costs  advantages  (driving 
from  low  LNG  price  and  fuel  efficiency)  and 
environmental advantages of LNG fuelled ships 
are  maintained  over  the  long  term,  so  as  to 
justify large investment in LNG ships   
Stricter  IMO  regulations  on  carbon  emissions, 
and government enforcement, favouring the use 
of LNG in ships   
IMO regulations not to include greenhouse gas 
emissions (methane) where LNG is seen to be 
at a disadvantage compared to other fuels 
Availability  of  finance  (loans,  grants  etc.)  for 
investment in LNG ships.   

3. 

4. 

Access to finance is key.  Investment costs for 
new  ships  are  significant 
for  shipping 
companies, whereas retrofits are also costly as 
larger  fuel  tanks  are  required  to  be  placed  in 
ship.   

5. 
Availability of adequate bunkering infrastructure 
6.  National legislation conducive to investments in 

ships and/or bunkering infrastructure 

8.3.4 Supply of LNG to off-grid consumers 
Table 43 describes the key prerequisites for effective implementation of the option of using LNG 
to  supply  off-grid  customers  in  Ukraine.  A  key  prerequisite  concerns  the  appropriate  price 
differential  between  LNG  and  currently  used  fuels  to  ensure  viability.  Another  prerequisite 
concerns the  introduction of  necessary  regulations concerning  LNG  storage and regasification 
installations at the sites of end-users (agriculture, mining, etc.). 

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Table 43: Prerequisites for supply of LNG to off-grid consumers72 

Prerequisites 

Rationale 

Involved 
country(ies) or 
parties 

Difficulty of 
implementation 

Uncertain 

LNG and fuel prices 
are determined in 
accordance with 
international demand 
and supply conditions 
(except in the case 
where LNG is sourced 
from an in-country 
liquefaction facility, in 
which the price is 
determined by gas 
import contracts)   

Under the sole control 
of Ukraine 

Low 

Market 
1  Sufficient price 

differential between LNG 
and the alternative fuel 
(as discussed in Section 
8.2.7)  

Critical – on/off 
condition, as 
switching to LNG 
requires an attractive 
price of LNG vis-à-vis 
the alternative fuel at 
the end use 

Legal & Regulatory 
1  Regulations and 

standards for the siting, 
design, construction and 
installation of LNG 
storage and 
regasification 
installations at the sites 
of end-users 
(agriculture, mining, etc.) 

Need to ensure 
safety, efficiency, 
quality and 
environmental 
protection by having 
standards concerning 
LNG storage and 
vaporisers, including 
mobile LNG tanks and 
vaporizers, and (if 
necessary) converting 
heavy equipment to 
use LNG as fuel.  

Table 44 outlines the key success factors for the implementation of the option of using LNG to 
supply  off-grid  customers.  These  factors  influence  the  speed  of  market  development.    These 
relate to a fiscal framework conducive to investments, reduction of subsidies and other favourable 
tax regimes for fuels competing with LNG, as well as awareness and promotional campaigns for 
LNG. 

Table 44: Key success factors for supply of LNG to off-grid consumers 

Key success factors 

Rationale 

1  Reduction of subsidies and favourite tax treatment 

of fuels competing with LNG, to make LNG more 
competitive and incentivise its use. 

2  Conducive fiscal framework (tax holidays, state 

grants) conducive to investment in LNG 
installations in farms  

3  Awareness and promotion campaigns for LNG. 

End consumers (e.g. farmers) should be 
educated as to the potential features and 
benefits of LNG in their respective fields.   

72 Points 5 – 14 of Table 39 also apply. 

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8.4 Priorities and policy directions 
On the basis of the viability assessment analysis performed, the option of LNG as fuel for trucks 
is viable, and could be implemented in a short-term horizon, as it involves decisions only of local 
actors and LNG can be sourced from the existing neighboring terminals. The Government could 
assess  feasibility  in  detail  further  and  take  relevant  policy  actions.  These  policies  could 
encompass,  at  the  minimum,  having  a  legal  and  regulatory  framework  conducive  to  the 
development of an LNG supply chain, and expand to cover incentives for the use of LNG. 

The  option  of  supplying  LNG  to  off-grid  consumers  could  be  viable  on  a  case-by-case  basis. 
Switching to LNG is primarily the consumer’s decision, and can be implemented over a short-term 
horizon,  as  LNG  can  be  sourced  from  existing  terminals.  To  enable  relevant  investments,  the 
Government  policy  should  target  the  removal  of  any  constraints  in  the  legal  and  regulatory 
framework, promote the use of LNG and gauge off-grid consumers’ interest.   

Concerning  the  potential  for  LNG  use  as  fuel  for  the  ships  operating  in  the  Black  Sea  and 
Ukraine’s  waterways,  this  option  would  require  the  Government  to  undertake  contextualized 
analysis,  as  LNG  use  is  not  appropriate  for  all  ships  and  would  depend  on  technical 
considerations, utilization and fuel economics and environmental requirements. This option could 
be developed over a medium-term horizon, as it would require involvement and large investments 
from ship owners for a diverse number of vessels. 

Regasified LNG sourced from neighbouring EU LNG terminals, aiming at gas-to-gas competition, 
is  marginally  viable  at  current  market/LNG  price  conditions,  and  does  not  enhance  security  of 
supply.  Consequently,  this  option  is  not  a  priority  from  a  policy  perspective,  but  it  can  be 
implemented in case relative LNG pricing is conducive for market players to take advantage of 
any potential opportunities.  

Development of a Ukrainian LNG terminal is viable only under conditions of LNG prices dropping 
considerably below current levels and ensuring very high utilisation of the terminal (over 50%).    
More importantly, there are several prerequisites for the LNG receiving terminal to be realized, 
that  affect  the  timing  of  its  implementation,  notably  the  uninterrupted  passage  of  LNG  vessels 
through the Bosporus Straits and securing of a sufficient market for regasified LNG. These render 
this option as medium to long-term.  

8.5 Proposed actions 
The Table below describes the actions that are deemed important in order to evaluate and prepare 
the identified applicable LNG market development options.  

Table 45: Proposed preparatory actions for developing the identified LNG options in Ukraine 

Proposed Actions 

Timing 

Initial / Preparatory Actions 
1 

Initiate dialogue with Turkish authorities regarding passage of 
LNG vessels through the Bosporus Straits 

Immediate 

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2  Perform update of the feasibility study for the development of 

LNG receiving terminal, including assessment of the prospects 
for selling LNG in the Ukrainian market  

3  Perform feasibility studies for the use of LNG as fuel for trucks 

Short-term / dependent on the 
progress of negotiations with 
Turkey 
Immediate 

and ships 

4  Develop a national policy framework for the use of LNG in road 
and water transport, deciding on the role that the State wishes 
to undertake 

Short-term / After the study is 
concluded (in case it is positive 
and Ukraine decides to pursue) 

Implementation Actions concerning LNG receiving terminal 
5  Gauge and secure the market’s interest to use the LNG 

Medium-term 

receiving terminal (e.g. binding market test) 

6  Explore investors’ interests in the LNG receiving terminal 
Implementation Actions aiming at developing use of LNG in transport sector 
7  Prepare the regulatory and legal framework (legal 

Medium to long-term 

8 

amendments, regulations, standards, permits and licenses, 
etc.) necessary for the development of the LNG supply chain 
If the State undertakes a proactive role in developing 
infrastructure, prepare the incentive mechanisms to attract 
investments 

9  Conduct awareness raising campaigns to attract end-users 

and investors’ interest 

10  Undertake initiatives to catalyze interest and seek joint 

commitments of stakeholders (suppliers, ports, ship owners) to 
develop the use of LNG in shipping 

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  

Short-term / based on national 
policy framework  
Short to medium-term / based 
on national policy framework 

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9  Regional Perspectives for LNG Market Development 
Some of the identified potentially viable options for LNG market development are of interest to 
two or more Eastern Partner countries.  

The  potential  development  of  the  LNG  receiving  terminal  in  Ukraine  (subject  to  an  agreement 
between Ukraine and Turkey for the crossing of LNG carriers through the Bosporus Straits) can 
facilitate supplies of LNG to other Eastern Partner countries (Figure 38): 

  Regasified gas can be supplied to Moldova through the Ukrainian system. This option 
seems  not  to  be  commercially  viable  and  therefore  would  not  be  used  by  Moldova 
under  normal  market  conditions,  but  potentially  in  case  of  a  supply  disruption  (see 
Section 7.2.2). 

  Opening the Bosporus Straits to LNG vessels could drive the development of a small 
LNG receiving terminal in Georgia that can be supplied from Ukraine (transhipment) or 
with dedicated LNG shipments.  

Figure 38: Regional perspective of LNG terminal in Ukraine 

Potential  development  of  a  liquefaction  terminal  in  Georgia,  allowing  exports  of  Caspian  gas 
though  the  Black  Sea  (subject  to  the  development  of  additional  export  potential  in  Azerbaijan 
and/or the commencement of gas supplies gas from Kazakhstan and Turkmenistan through the 
Caspian Sea), can develop an alternative corridor for LNG supplies to Eastern Partner countries 

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(Figure  39).  This  corridor  that  is  not  subject  to  an  agreement  with Turkey  on  crossing  of  LNG 
carriers through the Bosporus Straits, can allow:   

  Supply of LNG shipments to the LNG terminal in Ukraine. This option  would provide 
Ukraine  with  access  to  Caspian  gas  resources,  allowing  to  further  diversifying  its 
sources and routes.  

  Supply of regasified gas to Moldova through the Ukrainian terminal and system.   This 
option  seems  not  to  be  commercially  viable  and  therefore  would  not  be  used  by 
Moldova under normal market conditions, but potentially in case of a supply disruption 
(see Section 7.2.3). 

Figure 39: Regional perspective of liquefaction terminal in Georgia 

Initiatives for cooperation between Eastern Partners on smaller-scale infrastructure can also be 
explored.  In  particular,  the  interest  of  most  Eastern  Partner  countries  (Armenia,  Azerbaijan, 
Belarus,  Georgia,  Ukraine)  to  develop  a  use  of  LNG  in  road  transport  could  lead  to  the 
establishment of a regional network of LNG filling stations, that can facilitate accessibility of LNG 
to long-haul trucks operating in the region, and this provide incentives to truck owners to switch 
to LNG.  

Furthermore, the development of an LNG receiving or liquefaction and export terminal in Georgia 
would  allow  Armenia  to  have  access  to  LNG  supplies,  facilitating  the  development  of  an  LNG 
market. 

To foster development of LNG markets in the region, a number of actions could be considered for 
regional (or sub-regional) coordination and cooperation, presented in the Table below. 

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Table 46: Proposed actions for regional coordination and cooperation 

Actions 

Involved parties 

Timing 

1  Creation of sub-committees under the Eastern 
Partnership LNG working group, to facilitate 
dialogue, coordination and initiatives on key 
LNG issues (technical & standards, regulatory, 
market, etc.) 

2  Joint Georgia – Ukraine initiatives for 

addressing the Bosporus Straits’ constraints 

3  Harmonization of rules, regulations and 

standards, for LNG-fuelled trucks, and for trucks 
transporting LNG, for ease of transit through the 
Eastern Partner and EU countries 

4  Assess the potential for joint developing a 

small-scale liquefaction facility to supply LNG 
for trucks in the Caucasus region 

5  Coordination, and potentially preparation of 

regional development plan for the establishment 
of LNG filling stations in the Eastern Partner 
countries 

Regional level (All 
interested Eastern 
Partner countries) 

Immediate  

Sub-regional level 
(Georgia and Ukraine) 
Regional level (All 
interested Eastern 
Partner countries) 

Sub-regional level 
(Armenia, Azerbaijan 
and Georgia) 
Regional level (All 
interested Eastern 
Partner countries) 

Immediate 

Short-term 

Short-term 

Short-term 

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10  Recommendations for EU and Eastern Partners’ joint 
actions 

The analysis carried out in this Study shows that there is interest by the Eastern Partner countries 
and  potential  for  LNG  market  development,  both  for  gas-to-gas  and  gas-to-other  fuels 
competition.  However,  this  potential  can  only  be  gradually  realised,  given  the  investments 
requirements and the current market conditions. 

In catalysing this development, the Eastern Partner countries would benefit from the experience, 
practices  and  lessons  learned  of  EU  LNG  markets’  stakeholders.  Joint  actions  that  could  be 
considered with the objective of fostering cooperation and market development include: 

  Creation  of  sub-committees  under  the  Eastern  Partnership  LNG  working  group,  to 
facilitate  dialogue,  coordination  and  initiatives  on  key  LNG  issues  (technical  & 
standards, regulatory, market, etc.); 

  Knowledge  transfer  from  EU  counterparts  (from  the  whole  LNG  industry)  to  Eastern 
Partners,  on  LNG  technologies  and  benchmark  costs,  focusing  on  infrastructure 
development,  especially  small-scale  applications  (regasification,  liquefaction,  filling 
stations etc.); 

  Sharing of the experience gained through the Blue Corridor initiative, as a model case 
to develop the use of LNG in the transport sectors of Eastern Partners, by facilitating 
assessment and planning for the whole LNG supply chain; 

  Provision of know-how and technical assistance for the development of the legislative 
and  regulatory  framework,  technical  rules  and  standards  for  all  LNG  related 
infrastructure and equipment; 

  Development of a common IT platform for knowledge sharing of materials relevant to 

LNG markets; 

  Possibility to provide co-financing for selected projects of common interest through the 

European Network Instrument, or other financing mechanisms. 

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Annex 1: Overview of Eastern Partners’ gas markets 

A1.1. Armenia 
A1.1.1. Role of natural gas in the energy mix 
Natural gas is the dominant fuel in the energy mix of Armenia (Figure A. 1), in 2017 amounting to 
58% of the country’s total primary energy supply, and 48% of total final consumption. In the past, 
gas maintained similar shares in the energy mix. 

Figure A. 1: Natural gas in the energy mix of Armenia (2017) 

Total Primary Energy Supply 

Total Final Consumption 

Source: Ministry of Energy Infrastructures and Natural Resources of the Republic of Armenia, Energy Balance 2017 

A1.1.2. Natural gas supply & demand 
Without indigenous gas production, all gas demand is covered with imports. Most gas supplies 
are sourced from Russia (approx. 85%), the rest being imported from Iran. Annual demand has 
remained relatively constant in the past few years, ranging from 2.2 to 2.4 bcm (Figure A. 2). 

Gas imports from Russia are carried out in accordance with a gas supply contract signed between 
Gazprom Armenia, the vertically integrated gas supplier in Armenia, and Gazprom Export. The 
contract, valid until the end of 2019, foresees supply of up to 2.5 bcm/yr to Armenia. Import price 
for 2019 is set at 150 €/1000 m3, increased from 136 €/1000 m3 in 201873. Armenia and Russia 
are negotiating a new gas contract, with the Armenian side seeking to sign a five-year agreement 
on the price of gas, instead of the current annual readjustment74. 

73 https://ria.ru/20181231/1548952211.htmlhttps://ria.ru/20181231/1548952211.html  
74 http://tass.com/economy/1052207  

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Figure A. 2: Evolution of natural gas supply and demand in Armenia75 

Source: Ministry of Energy Infrastructures and Natural Resources of the Republic of Armenia, Energy Balance 2017 

Imports from Iran are being carried out under a swap scheme that foresees supply of up to 0.5 
bcm/yr of Iranian gas to Armenia, and export of Armenian electricity to Iran (3.2 kilowatt-hours of 
electricity are exported in exchange for 1 cubic meter of gas)76. The 20-year swap contract entered 
into force in 2009. 

Figure A. 3: Natural gas balance in Armenia (2017) 

Source: Ministry of Energy Infrastructures and Natural Resources of the Republic of Armenia, Energy Balance 2017 

Figure A. 3 presents the 2017 balance of the natural gas sector in Armenia. The largest part of 
gas consumption is for electricity generation (the only fossil fuel used in thermal power plants) 
and for heating at households (only biomass is used as an alternative fuel). Use of natural gas in 

75 Demand includes net stock changes in UGS, and losses of distribution and transmission systems. 
76 https://financialtribune.com/articles/energy/76842/iran-gas-export-to-armenia-at-250-mcm-in-8-months  

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the transport sector, as CNG, is very high. In 2017, 373 CNG filling stations are in operation in 
the country, and according to Gazprom Armenia, around 77% of the vehicles operate with CNG77.   

A1.1.3. Natural gas prices 
End-user  prices  for  all  gas  consumers  are  regulated,  set  by  the  Public  Services  Regulatory 
Commission (PSRC). Customer categories have been established, for which different prices are 
set. The Table below presents the current end-user prices applied in the market. 

Table A. 1: Regulated end-user prices in Armenia 

Customer Category 

Regulated price (excluding 
VAT) in €/1000 m3 

Vulnerable household– annual consumption up to 600 m3 

Vulnerable household– annual consumption over 600 m3 

154 

214 

Agriculture (depending on season and consumption) 

160 – 214  

Other consumers – consumption up to 10,000 m3 

Other consumers – consumption over 10,000 m3 

214 

183 

Source: PSRC, Tariffs 

A1.1.4. Natural gas infrastructure 
The gas transmission system of Armenia spreads throughout the country. The total length of the 
main pipelines and their branches is 1682 km. According to the Ministry of Energy Infrastructures 
and Natural Resources, around 95% of Armenia is gasified77.  

Armenia is interconnected with Georgia and Iran (Figure A. 4). The North-South Pipeline, with a 
capacity  of  3.65  bcm/yr,  transits  Russian  gas  to  Armenia  (Koghb)  through  Georgia.  The  Iran-
Armenia pipeline is 142 km long, connecting Tabriz (Iran) with Meghri (Armenia) with a delivery 
capacity of 2.3 bcm/yr78. 

77  Ministry  of  Energy  Infrastructures  and  Natural  Resources  of  the  Republic  of  Armenia,  Explanation  on  the 
development of Armenia's Energy Balance 2015, 2016, 2017, Available at: http://www.minenergy.am/en/page/554,  
78 World Bank,Armenia Power Sector Policy Note, 2014, Available at: 
http://documents.worldbank.org/curated/en/488891467998515807/pdf/94187-REVISED-WP-P133834-PUBLIC-
Box391432B-Armenia-Power-Policy-Note-full-version-very-final-ENGLISH.pdf  

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Figure A. 4: Armenian gas transmission system 

Source: Gazprom, World Bank 

The transmission system is connected to the Abovyan UGS, with capacity of 135 mcm, used to 
cover  the  seasonal  and  peak  demand  of  the  gas.  In  2017,  58  mcm  were  withdrawn  from  the 
storage, and 43 mcm injected77.  

Iran,  Georgia  and  Armenia  are  currently  discussing  the  potential  of  transiting  Iranian  gas  to 
Georgia, without however any concrete agreement signed yet.  

A1.1.5. Market structure 
Armenia’s gas market has a monopolistic structure. All gas activities are concentrated within the 
vertically  integrated  holding  structure  of  Gazprom  Armenia  (owned  100%  by  Gazprom).  The 
company  operates  as  a  single  gas  distributor  and  supplier;  its  subsidiary  TransGas  operates 
transmission system and storage in the country (Figure A. 5). Erevan thermal power station holds 
a license for gas imports, as it is receiving the gas supplies from Iran. 

PSRC is the country’s energy regulator, responsible for issuing licenses, establishes market rules 
and contractual terms of gas supply contracts, sets regulated tariffs for end-users.  

Figure A. 5: Key stakeholders in Armenia’s gas supply chain  

A1.1.6. Regulatory framework 
The gas sector is governed by the “Energy Law of the Republic of Armenia”, adopted in March of 
2001. The Law does not provide for opening of the gas market. While non-discriminatory access 
to the transmission system is foreseen, no further relevant regulation has been established. The 
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market rules in force, issued by PSRC (“Rules for Natural Gas Supply and Use”, of September 
2005),  focus  on  the  obligations  of  supplier  and  end-users,  and  connection  rules,  without  any 
provisions related to the operation of the gas market. 

Table A. 2 below, provides an outline of the key regulatory framework provisions related to the 
overall market operation, transmission system and off-grid supplies of LNG.  

Table A. 2: Overview of regulatory framework in Armenia (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Energy Law of the Republic of Armenia (2001) 

Licensing of gas stakeholders 

 

Entities undertaking activities in the gas sector, 
including import/export, transportation, 
distribution. Distribution licensee is entitled to 
supply end-users (no separate supply license) 

Eligibility of final consumers to choose supplier   

Transparent and non-discriminatory third-party 
access on the transmission system 

 

Not foreseen in the national legislation. 
Suppliers entitled to sell gas must hold a 
distribution license 

Non-discriminatory access to the system is 
foreseen, but without further requirements of 
supporting regulations 

Rules for access to storage  

  No rules in place 

Unbundling of system operators 

Transmission system operation 

Establishment of capacity allocation 
mechanisms 

Establishment of congestion management 
procedures 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

Definition of tariffs at cross-border entry/exit 
points 

Publication of gas technical specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

 

Not foreseen in the national legislation 
(Transgaz fully dependent on Gazprom 
Armenia) 

  No such provisions have been established 

  No such provisions have been established 

  No such provisions have been established 

  No such provisions have been established 
  No publication requirement 
  No such provisions have been established 

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A1.2. Azerbaijan 
A1.2.1. Role of natural gas in the energy mix 
With Azerbaijan being a producer and net exporter of oil & gas, hydrocarbons cover almost fully 
the primary energy supply of the country, with natural gas having a share of 61% (Figure A. 6). 
Although the majority of produced gas is exported, the fuel also plays an important role in the 
country’s  total  final  consumption  (total  share  of  39%)  being  the  dominant  fuel  for  electricity 
generation, industries, and households.   

Figure A. 6: Natural gas in the energy mix of Azerbaijan (2017) 

Total Primary Energy Supply 

Total Final Consumption 

Source: State Statistical Committee of the Republic of Azerbaijan, Energy Balance 2017 

A1.2.2. Natural gas supply & demand 
Azerbaijan is a net gas exporter. In the period 2013 – 2017, gas production ranged from 18 to 19 
bcm/yr, while annual consumption did not exceed 4.6 bcm/yr (Figure A. 7). In 2016 and 2017, 
Azerbaijan imported volumes of gas from Iran and Russia79.  

Gas imports from Russia restarted in 2017. According to EIA, gas is stored in the Garadagh and 
Galmaz UGSs and used for increasing oil production and potentially for gas to Iran in the winter 
months80.  Azerbaijan  and  Iran  hold  a  swap  agreement,  according to  which  Azerbaijan  exports 
small  quantities  of  gas  to  Iran  through  the  Hajiqabul-Astara  pipeline  and  receives  gas  at  the 
Nakhchivan  region.  According  to  the  Ministry  of  Energy,  additional  gas  volumes  are  being 
imported from Iran to Azerbaijan through the Astara-Gazi pipeline. 

79 Ministry  of  Energy  of  the  Republic of  Azerbaijan  (2017).  2017  Report on  the  work carried  out  in  fuel and energy 
sector. Available online at: http://www.minenergy.gov.az/docs/Illik_Hesabat_2017.pdf  
80 https://www.eia.gov/beta/international/analysis_includes/countries_long/Azerbaijan/azerbaijan_bkgd.pdf 

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Figure A. 7: Evolution of natural gas supply and demand in Azerbaijan 

Source: State Statistical Committee of the Republic of Azerbaijan, Energy Balance 2017 

Almost  80%  of  Azerbaijan’s  gas  is  produced  from  the  Shah  Deniz  and  Azeri-Chirag-Gunashili 
(ACG)  off-shore  fields,  that  are  being  operated  by  international  consortia,  with  participation  of 
SOCAR. The remaining gas production comes from small on-shore and off-shore fields operated 
by SOCAR. According to EIA, the country’s proved reserves in January 2018 amounted to around 
990 bcm, most of which in Shah Deniz. The second phase of the field’s development (Shah Deniz 
2)  came  online  in  2018  and  its  output,  once  production  reaches  a  plateau,  is  expected  at  16 
bcm/yr81.  

The majority of current gas exports are shipped through the SCP to Turkey (6.3 bcm in 2017), 
and  the  rest  to  Georgia  (0.8  bcm  through  SCP  and  1.4  bcm  through  the  Magomed-Gazakh 
pipeline  in  2017)79.  According  to  EIA,  all  gas  outputs  from  Shah  Deniz  2  have  already  been 
contracted, for exports to Turkey and Europe80.  

Figure A. 8: Natural gas balance in Azerbaijan (2017) 

Source: State Statistical Committee of the Republic of Azerbaijan, Energy Balance 2017  

81

 http://www.socar.com.tr/en/corporate-communication/news/2018-news/2018/07/02/shah-deniz-2-begins-gas-

deliveries-to-turkey-with-tanap-project 

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Figure A. 8 presents the 2017 balance of the natural gas sector in Azerbaijan. More than half of 
gas (54%) is consumed in TPPs and CHPs, while households consume another 28%.   

A1.2.3. Natural gas prices 
The transportation, wholesale and end-user prices of gas in Azerbaijan are regulated, defined by 
the  Tariff  Council  of  Azerbaijan  Republic.  The  transportation  tariff  is  distance  based,  set  at 
1 €/1000 m3 per 100km, and the wholesale price is 39 €/1000 m3. End-user prices depend on the 
customer category (Table A. 3). 

Table A. 3: Regulated end-user prices in Azerbaijan 

Customer Category 

Regulated price (including 
VAT) in €/1000 m3 

Residential – annual consumption up to 2200 m3 

Residential – annual consumption over 2200 m3 

Non-residential 

Power generation – consumption over 10 mcm per month 

Source: Tariff Council of Azerbaijan Republic, Tariffs 

52 

104 

104 

62 

A1.2.4. Natural gas infrastructure 
Figure A. 9 presents the transmission system of Azerbaijan, and the pipelines with neighbouring 
countries. The import and export pipelines include80, 82: 

  South Caucasus Pipeline (SCP): Transports gas from the Shah Deniz field to Turkey, 
having also a small offtake in Georgia. SCP is owned by an international consortium 
(BP – operator (28.8%), TPAO (19%), Petronas (15.5%), LUKoil (10%), NICO (10%), 
AzSCP (10%), SNG Midstream (6.7%)). Its total length is 691km, running 443 km in 
Azerbaijan and 248 km in Georgia, and its initial capacity is 7.4 bcm/yr. In mid-2018 
the  South  Caucasus  Pipeline  Extension  (SCPX)  was  completed,  increasing  capacity 
to 23.4 bcm/yr83, once Shad Deniz 2 production reaches a plateau. 

  Gazi-Magomed-Mozdok  Pipeline:  Connects  the  Azeri  and  Russian  transmission 
systems, and is currently used for imports of Russian gas to Azerbaijan (in the past it 
was also used on the opposite flow, exporting Azeri gas to Russia). Its total length is 
740 km and its capacity 5 bcm/yr. 

  Gazi-Magomed-Astara  Pipeline:  Connects  Azerbaijan  with  Iran,  and  is  used  for  gas 
swaps, and exports to Iran. Its total length is 274 km and maximum capacity 1.8 bcm/yr. 

  Azerbaijan  –  Georgia  Pipeline:  The  main  export  route  of  Azeri  gas  to  Georgia.  Its 

capacity is 1.8 bcm/yr. 

82 BP, South Caucasus pipeline, Available At:   
https://www.bp.com/en_az/caspian/operationsprojects/pipelines/SCP.html  
83 South Caucasus Pipeline Consortium https://www.sgc.az/en/project/scp 

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Figure A. 9: Azeri gas transmission system 

Source: U.S. Energy Information Administration (EIA), Azerbaijan Country Profile 

Azerbaijan has two UGSs, in Garadagh and Galmaz, with aggregate working volume of 5 bcm. 
The storages are used to cover winter demand peaks80. 

There  are  plans  for  developing  an  additional  export  route  of  Azeri gas  to  Europe,  through  the 
Azerbaijan-Georgia-Romania  Interconnector  (AGRI)  project,  that  foresees  development  of  a 
liquefaction terminal in Georgia and export of LNG to Romania through the Black Sea, where it 
will be regasified and supplied to Romania, Hungary and other EU markets. Capacity of the project 
can  be  modular,  ranging  from  2  to  8  bcm/yr 84.  Development  of  the  project  depends  on  the 
availability of gas in Azerbaijan, and its timeline of implementation has been set after 2024-2685.  

A1.2.5. Market structure 
SOCAR is the vertically integrated gas company of Azerbaijan (100% state owned), with all gas 
transportation,  distribution,  storage  and  supply  activities  within  the  country  carried  out  by  its 
subsidiaries  (Figure  A.  10).  Azerigaz  Production  Union  is  responsible  for  the  transmission, 
distribution and sale of gas in Azerbaijan, as well as for the transportation of SOCAR gas to Iran, 
Georgia and Russia. The Gas Export Department of SOCAR is responsible for the exports and 
imports of gas in the country (including swaps with Iran). Azneft Production Union is the operator 
of Azerbaijan’s UGSs. 

84 AGRI LNG Project Description, Available at: http://www.agrilng.com/agrilng/Home/DescriereProiect  
85 https://www.azernews.az/oil_and_gas/146939.html 

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The  mandate  of  the  Azerbaijan  Energy  Regulatory  Agency  (AERA)  is  to  regulate  gas  supply. 
However,  AERA  still  has  not  issued  any  relevant  regulations.  The  Tariff  Council  of  Azerbaijan 
Republic is responsible for approving regulated tariffs for the gas sector, following proposals by 
SOCAR. 

Figure A. 10: Key stakeholders in Azerbaijan’s gas supply chain86 

A1.2.6. Regulatory framework 
The gas sector is governed by the “The Law of the Republic of Azerbaijan on Gas Supply”, of 
1998,  amended  in  2011.  The  Law  does  not  include  any  provisions  related  to  market  opening, 
access to the systems, or even licensing of gas stakeholders. 

Table A. 4 below, provides an outline of the key regulatory framework provisions related to the 
overall market operation, transmission system and off-grid supplies of LNG.  

Table A. 4: Overview of regulatory framework in Azerbaijan (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Licensing of gas stakeholders 

The Law of the Republic of Azerbaijan on Gas 
Supply (2011) 

  No licensing rules foreseen in the national 

legislation 

Eligibility of final consumers to choose supplier    Not foreseen in the national legislation. 
Transparent and non-discriminatory third-party 
  Not foreseen in the national legislation. 
access on the transmission system 
  Not foreseen in the national legislation. 
  Not foreseen in the national legislation. 

Unbundling of system operators 

Rules for access to storage  

Transmission system operation 

Establishment of capacity allocation 
mechanisms 

 

No such provisions have been established. 
Capacity managed only by the owners of the 
systems 

86 The graph presents only the stakeholders active in the internal Azeri gas market. International consortia operating 
gas fields (Shah Deniz, ACG) and international pipelines (SCP are not included). 

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Establishment of congestion management 
procedures 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

Definition of tariffs at cross-border entry/exit 
points 

Publication of gas technical specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

  No such provisions have been established 

  No such provisions have been established 

  No such provisions have been established 
  No publication requirement 
  No such provisions have been established 

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A1.3. Belarus 
A1.3.1. Role of natural gas in the energy mix 
Natural gas is the second largest fuel supplied in Belarus, after crude oil, with a 2017 share of 
43% in the total primary energy supply of the country. It is the dominant fuel for power plants and 
district heating (over 90% of total fuel consumption). Most gas supplies are transformed to heat 
and electricity; as a result, gas has just 18% share in total final consumption.    

Figure A. 11: Natural gas in the energy mix of Belarus (2017) 

Total Primary Energy Supply 

Total Final Consumption 

Source: National Statistical Committee of the Republic of Belarus (Belstat), Energy Balance 2017 

A1.3.2. Natural gas supply & demand 
The gas market is dependent on imports of Russian gas. Annual demand over the past 5 years 
has been within the range of 19 to 20.5 bcm (Figure A. 12).  

Figure A. 12: Evolution of natural gas supply and demand in Belarus 

Source: National Statistical Committee of the Republic of Belarus (Belstat), Energy Balance 2017 

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Imports of Russian gas to Belarus are carried out in accordance with the gas supply and transit 
contract  signed  in  December  2014  that  was  extended  in  2018  for  supplies  up  to  2020.  Gas 
delivery (border) prices are set at 130 €/1000 m3 in 2017, 117 €/1000 m3 in 2018 and 115 €/1000 
m3 in 201987. 

Figure A. 13 presents the 2017 balance of the natural gas sector in Belarus. Over 70% of gas is 
being used for electricity and heat generation, while the rest is mainly consumed in households 
and industries. 

Figure A. 13: Natural gas balance in Belarus (2017) 

Source: National Statistical Committee of the Republic of Belarus (Belstat), Energy Balance 2017 

Gas transit volume via Belarus to Ukraine, Poland, Lithuania and Kaliningrad region of Russian 
Federation reached 42.5 bcm in 2018, increased from 41.3 bcm in 201788. 

To reduce dependence of electricity and heat generation from imported gas supplies, Belarus will 
introduce nuclear energy in its energy mix. A nuclear power plant is being build (commissioning 
work began in April 2019), with installed capacity of 2.4 MW89. As a result of the NPP operation, 
gas demand is expected to decrease in the next years (Figure A. 14). 

87

 https://neftegaz.ru/news/transport-and-storage/193568-obem-tranzita-gaza-cherez-belarus-v-2018-g-uvelichilsya-

na-3/  
88

 https://neftegaz.ru/news/transport-and-storage/193568-obem-tranzita-gaza-cherez-belarus-v-2018-g-uvelichilsya-

na-3/  
89 World  Nuclear  Association  (April 2019):  http://www.world-nuclear.org/information-library/country-profiles/countries-
a-f/belarus.aspx  

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Figure A. 14: Forecasted gas demand in Belarus 

Source: National Statistical Committee of the Republic of Belarus (Belstat); Energy Security Conception of Republic of 
Belarus (Resolution No 1084 dated 23/12/2015) 

A1.3.3. Natural gas prices 
End-user prices for all gas consumers are regulated, set by the Ministry of Energy of Belarus. 
Different  prices  are defined for  household and non-household consumers,  varying  on gas use 
and seasonality (Table A. 5). 

Prices include the Gazprom Transgaz Belarus tariff for gas transportation (in 2017 15.5 €/1000 
m3, excluding VAT) and Beltopgaz tariff for distribution (in 2017 5.8 €/1000 m3)90. 

Table A. 5: Regulated end-user prices in Belarus 

Customer Category91 

Regulated price (VAT 
excluded) in €/1000 m3 

Residential (for heating) - winter period 

Residential (for heating) - summer period 

Residential (other uses) 

Services - up to 600 mcm/yr 

Heat plants - up to 600 mcm/yr 

Agriculture (depending on season) - up to 600 mcm/yr 

Manufacturing (depending on products) - up to 600 mcm/yr 

Fertilizing industry - up to 600 mcm/yr 

Other types of non-residential consumers - up to 600 mcm/yr 

Non-residential consumers - up to 600 mcm/yr 

Source: Ministry of Energy of Belarus 

50 – 52 

179.5 

179.5 

223.0 

143.0 

145 - 196 

95 - 219 

136 

224 

341 

90 https://www.sb.by/articles/skolko-stoit-prirodnyy-gaz-v-belarusi-.html; 
http://pravo.by/document/?guid=3871&p0=W21631316 
91 Households  without  installed  meters  have  different  regulated  prices,  on  the  basis  of  number  of  habitants  (for 
cooking/hot water) and dwelling size (for heating) 

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A1.3.4. Natural gas infrastructure 
The total length of the transmission system in Belarus is over 7,900 km, covering most regions 
of the country. Part of this system (around 2,500 km) is used for transit of Russian gas to the 
EU. Additionally, the dedicated transit pipeline Yamal-Europe, with technical capacity of 32.9 
bcm/yr, runs 575 km through Belarus92 (Figure A. 15). 

Figure A. 15: Gas transmission system in Belarus 

Source: ENTSOG, Gazprom, Ukrtransgaz 

There  are  3  underground  storages  connected  to  the  transmission  system  of  Belarus. 
Osipovichsky UGS, with working volume of 0.3 bcm, Pribugskoye UGS, with working volume of 
0.4 – 0.6 bcm, and Mozyr UGS, with peak daily capacity of 8 mcm/d. There are plans for extending 
the maximum working volume of the Mozyr UGS to 1 bcm, by 202092. 

In July 2018, Gazprom Transgaz Belarus announced their plans for developing an LNG supply 
chain  development,  by  carrying  out  engineering  works  of  the  first  small-scale  LNG  production 
plant in Belarus. Its aim is to use gas in transit transport via Belarus and in farming machinery93. 

92 Gazprom Transgaz Belarus, http://belarus-tr.gazprom.ru/about/activities/ ; Gazprom, 
http://www.gazprom.com/projects/yamal-europe/ 
93 https://www.belta.by/interview/view/gazprom-transgaz-belarus-v-2018-godu-investiruet-v-obnovlenie-
gazotransportnoj-sistemy-br169-mln-6360/   

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A1.3.5. Market structure 
The  gas  market  of  Belarus  is  monopolistic.  Gazprom  Transgaz  Belarus  (100%  subsidiary  of 
Gazprom) is the owner and operator of the Belarusian transmission and storage infrastructure, 
as  well  as  responsible  for  the  operation  of  the  Yamal-Europe  Pipeline,  owned  by  Gazprom. 
Gazprom Transgaz Belarus also holds the import contracts with Gazprom and sells gas to the 
state-owned company Beltopgaz that is responsible for the supply and distribution of gas in the 
market. Retail sales are carried out through the regional subsidiaries of Beltopgaz.  

There is no independent energy regulator in Belarus. The Ministry of Antimonopoly Regulation 
and  Trade  is responsible for setting  the regulated  end-user  prices  in the gas  sector,  while the 
Ministry of Energy is responsible for monitoring the market operation. 

Figure A. 16: Key stakeholders in Belarus gas supply chain 

A1.3.6. Regulatory framework 
The  gas  sector  is  governed  by  the  Natural  Monopolies  Law  No  162-3/911  of  December  2002 
(amended in 2006, 2009, 2014 and 2019) and the Law of the Republic of Belarus on Gas Supply 
No 176-3 of January 2003 (amended in 2006, 2008, 2009 and 2011). The legislative framework 
does  not  include  any  provisions  related  to  market  opening,  access  to  the  systems,  or  even 
licensing of gas stakeholders.  

Table A. 6 below, provides an outline of the key regulatory framework provisions related to the 
overall market operation, transmission system and off-grid supplies of LNG.  

Table A. 6: Overview of regulatory framework in Belarus (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Licensing of gas stakeholders 

Natural Monopoly Law (2014), Law on Gas Supply 
(2011) 

  No licensing rules foreseen in the national 

legislation 

Eligibility of final consumers to choose supplier    Not foreseen in the national legislation. 
Transparent and non-discriminatory third-party 
  Not foreseen in the national legislation. 
access on the transmission system 
  Not foreseen in the national legislation. 
  Not foreseen in the national legislation. 

Unbundling of system operators 

Rules for access to storage  

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Transmission system operation 

Establishment of capacity allocation 
mechanisms 

Establishment of congestion management 
procedures 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

Definition of tariffs at cross-border points 

Publication of gas technical specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

  No such provisions have been established 

  No such provisions have been established 

  No such provisions have been established 
  No such provisions have been established 
  No such provisions have been established 
  No such provisions have been established 

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A1.4. Georgia 
A1.4.1. Role of natural gas in the energy mix 
Natural  gas  has  the  largest  share  in  Georgia’s  total  primary  energy  supply.  The  total  final 
consumption is quite diversified, with natural gas, oil products and electricity being mostly used 
(Figure A. 17).    

Figure A. 17: Natural gas in the energy mix of Georgia (2017) 

Total Primary Energy Supply 

Total Final Consumption 

Source: National Statistics Office of Georgia, Energy Balance 2017 

A1.4.2. Natural gas supply & demand 
Annual gas demand in Georgia is within the range of 2.2 to 2.5 bcm/yr. The market is almost fully 
dependent  on  imports,  as  indigenous  production  accounts  to  less  than  1%  of  consumed  gas. 
Azerbaijan  is  the  main  supplier  of  Georgia,  while  additional  volumes  are  received  through  the 
SCP, as compensation for the transit of Azeri gas to Turkey (in lieu of transit fee). Some small 
volumes of Russian gas are being supplied, in cases where Azeri gas is not sufficient to cover 
high peak demand. Finally, very small gas volumes from the gas transited to Armenia are being 
swapped (Figure A. 18). 

Figure A. 18: Evolution of natural gas supply and demand in Georgia 

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Source: Georgian National Energy and Water Supply Regulatory Commission, Annual Report 2018 

Georgia and the Shah Deniz consortium hold two sale-purchase contracts, one allowing Georgia 
to procure up to 5% of the gas flows transited through SCP (referred to as optional gas)94, which 
expires in 2026,  and one that allows Georgia to purchase up to 500 mcm/yr from the Shah Deniz 
consortium (referred to as additional gas), at discounted prices, which ends in 202595.  

Georgia also has a transit agreement with Gazprom Export, for the transit of gas to Armenia. Until 
2016, Georgia received gas as compensation for transit, 10% of annual gas flows to Armenia. 
However, starting 2017, monetary compensation for the transit gas is being provided.  

Figure A. 19: Natural gas balance in Georgia (2017) 

Source: Georgian National Energy and Water Supply Regulatory Commission, Annual Report 2017 

Figure  A.  19  presents  the  2017  balance  of  the  natural  gas  sector  in Georgia.  The  largest  gas 
consumer is the residential sector (39% in 2017), followed by electricity generation (34%), and 
industry (17%). Use of CNG for road transport is also substantial, accounting for 11% of total gas 
demand. 

Gas consumption is characterized by high seasonality. This is a result of the large use of gas for 
heating in residential and small non-residential consumers, and at thermal power plants96.  

Gas demand is foreseen to grow over the next decade (Figure A. 20). The main drivers for this 
increase  are  the  recovery  of  the  commercial  and  industrial  sector,  further  gasification  of  the 
country and penetration of gas in households, and use of gas-fired power plants as back-up for 
developing renewables generation. 

94 For Phase 1 of Shah Deniz development the optional gas volumes were up to a maximum of 330 mcm/yr (5% of the 
6.6 bcm/yr transited to Turkey). Phase 2 of Shah Deniz development and transit volumes via SCP of up to 22 bcm/yr, 
results in a proportional increase in the maximum volumes of optional gas. 
95 Partnership for Social Initiatives (2017), 
https://www.naturalgasworld.com/pdfs/Georgias%20Gas%20Market%202.pdf 
96 GNERC, 2017 Annual Report 

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Figure A. 20: Demand forecasts for Georgian gas market 

Source: Department of Strategic Planning and Projects of GOGC 

A1.4.3. Natural gas prices 
The end-user prices for households and thermal power plants are regulated, and based on the 
optional and additional gas received as tariff compensation and procured at discounted import 
prices through the SCP (social gas). The regulated tariffs are set by GNERC. For the rest of the 
consumers, prices are deregulated (commercial gas). 

The gas transmission tariff is common for all regulated and deregulated consumers; it is proposed 
by the TSO (GGTC) and approved by GNERC. It is defined using postage-stamp approach, while 
currently GNERC is in the process of developing entry-exit tariffs. For the period up to December 
2018, the transmission tariff was set at 6.1 €/1000 m3, excluding VAT. 

The end-user prices, apart from the transmission fee, also includes a distribution tariff (different 
for each distribution system) and a supply price (common for all systems, based on the transit 
compensation). 

Table A. 7: Indicative regulated end-user prices in Georgia (2017) 

DSO 

Regulated price in €/1000 m3 
(excluding VAT) 

KazTransGas Tbilisi LLC 

Socar Georgia Gas LLC 

SakOrgGaz JSC  

Arzu-Gaz LLC 

126 

155 

155 

151 

Source: Georgian National Energy and Water Supply Regulatory Commission, Annual Report 2017 

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Prices for social gas are considerably lower than that of commercial gas. As a result, there are 
significant price differences between household customers, and consumers directly connected to 
the transmission system (Figure A. 21).  

Figure A. 21: Prices for distribution and transmission consumers in Georgia (2017) 

Regulated price (indicatively price for Socar Georgia 
Gas LLC is presented) 

Non- Regulated price (indicatively price for consumers 
with demand range 2.5 – 25 mcm/yr) 

Sources: National Statistics Office of Georgia, Georgian National Energy and Water Supply Regulatory Commission 

A1.4.4. Natural gas infrastructure 
The  Georgian  gas  transmission  system  is  around  2,000  km  long.  The  largest  part  of  the 
country has access to gas, as a wide gasification plan is being implemented.  

There  are  no  gas  compression  stations  or  UGSs  in  Georgia,  and  to  maintain  appropriate 
transmission pressure, the transmission operator relies on neighbouring systems, particularly 
that of Azerbaijan and Russia. As a result of low pressure levels at the Azerbaijan  – Georgia 
pipeline during winter period, gas flows are not sufficient to fully cover peak demand, creating 
issues with security of supply97.   

97

 GNERC  Presentation  on 

Investments 

in  Storage/Transmission,  available  at:  https://www.energy-

community.org/dam/jcr:8796f176-2963-4a91-86ca-cf052df56fed/GF092018_GNERC.pdf 

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Figure A. 22: Gas transmission system in Georgia 

Source: GOGC Department of Strategic Planning and Projects 

There are two transit pipelines in place in Georgia. The South Caucasus Pipeline, transiting 
gas  from  Azerbaijan  to  Turkey,  has  a  small  offtake  linked  to  the  Georgian  national 
transmission system. The North-South Pipeline, transiting gas from Russia to Armenia, is also 
connected to the transmission system. At the exit to Armenia, a small loop (after the metering 
station) allows transportation of gas to some small consumers in South Georgia.   

Due to the low pressure of the transmission system, there are over 400 exit points, mainly to direct 
consumers, a very high number considering the length of the system. 

To  enhance  security  of  supply,  the  Georgian  Oil  and  Gas  Corporation  (GOGC)  is  planning  to 
construct  an  underground  storage  at  the  Samgori  South  Dome  field,  with  working  volume  of 
around 210 mcm, maximum injection rate of 2.5 mcm/d and maximum withdrawal of 5-6 mcm/d. 
The  cost  of  the  project  is  estimated  at  220-250  mil.  EUR,  and  its  commissioning  foreseen  by 
202498. 

A1.4.5. Market structure 
The  Georgian  gas  market  is  divided  in  two  segments:  the  social  segment,  that  includes  the 
households and TPPs receiving “social gas” at regulated low prices, and the commercial segment 
that includes all other consumers.  

For the social segment, GOGC (state-owned), that has the role of state supplier imports optional 
and  additional  gas  of  SCP  through  SOCAR  Gas  Export-Import  LLC,  and  supplies  it  to  the 
corresponding retail suppliers and to TPPs. 

98 GOGC Department of Strategic Planning and Projects 

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For the commercial segment, private entities (SOCAR subsidiaries) are active to import gas and 
sell it on a wholesale level. In 2017, 9 suppliers provided trade of natural gas on the wholesale 
level, and supplied consumers directly connected at the transmission system, and retail suppliers 
selling gas to non-households. On retail level, there are 26 distribution licensees, most of which 
offer bundled distribution and supply services (in 2017 only 4 distribution licensees did not carry 
out  supply  activities).  As  third-party  access  is  possible  on  distribution,  more  than  one  retail 
suppliers are active on 5 distribution systems, selling gas to large non-household consumers.  

The  state-owned  Georgian  Gas  Transportation  Company  (GGTC)  is  the  transmission  system 
operator of the national system. GGTC leases the system from GOGC, and is responsible for its 
operation and maintenance (development is responsibility of GOGC).  

GNERC has the mandate to issue licenses for gas transmission and distribution, control license 
conditions, and set and regulate tariffs.  

Figure A. 23: Key stakeholders in Georgian gas supply chain 

A1.4.6. Regulatory framework 
Georgia, as Contracting Party of the Energy Community Treaty, is obliged to conform with the 3rd 
Energy  Package  requirements.  However,  as  the  country  borders  only  with  non-Energy 
Community  and  non-EU  countries,  it  is  not  obligatory  to  implement  the  3rd  Energy  Package 
provisions at the cross-border interconnections. 

The gas sector is currently governed by the “Law of Georgia on Electricity and Natural Gas”, (No 
15(22) of April 1999). A new Energy Law is being drafted, to comply with the 3rd Energy Package 
provisions for electricity and gas. To facilitate market competition, market rules and transmission 
and  distribution  grid  codes  were  launched  in  2018,  with  GNERC  Decree  No  22  of  31/8/2018. 
These will be updated and enhanced once the new Energy Law enters into force. 

Table A. 8 below, provides an outline of the key regulatory framework provisions related to the 
overall market operation, transmission system and off-grid supplies of LNG.  

Table A. 8: Overview of regulatory framework in Georgia (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Licensing of gas stakeholders 

Law of Georgia on Electricity and Natural Gas (1999) 
– new Energy Law is being drafted 
  Licenses are only issued for transmission and 
distribution activities. Suppliers are not required 

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Eligibility of final consumers to choose supplier   

Transparent and non-discriminatory third-party 
access on the transmission system 

 

to have a license (but must be registered with 
the TSO to use the transmission system) 

Consumers are able to switch supplier. It is 
noted that households and TPPs always 
receive social gas 

Grid code has been released, and model 
contracts for network users are public. 
Publication of information to be addressed with 
the new legislation 

Rules for access to storage  

Unbundling of system operators 

Transmission system operation 

  To be drafted once the new legislation enters 

into force 

  Requirement set in the new legislation 

Establishment of capacity allocation 
mechanisms 

  To be developed in a revision of the grid code, 

applying the new legislation 

Establishment of congestion management 
procedures 

  To be developed in a revision of the grid code, 

applying the new legislation 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

  Agreements focus on technical issues and are 

confidential 

Definition of tariffs at cross-border entry/exit 
points 

Publication of gas technical specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

points are set 

  No specific tariffs for entry/exit interconnection 
  Published in the GGTC website 
  To be developed in a revision of the grid code, 

applying the new legislation 

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A1.5. Moldova 
A1.5.1. Role of natural gas in the energy mix 
Natural gas and oil products are the two main sources in the energy supply mix of Moldova.  A 
large part of gas supplies is used for electricity and heat generation; as a result, gas has just 16% 
share in total final consumption. It is worth noting that biofuels are a main source in the energy 
mix, used for heating of households (Figure A. 24).    

Figure A. 24: Natural gas in the energy mix of Moldova (2017)99 

Total Primary Energy Supply 

Total Final Consumption 

Source: National Bureau of Statistics of the Republic of Moldova, Energy Balance 2017 

A1.5.2. Natural gas supply & demand 
Indigenous gas production in Moldova is negligible, and consequently the country relies only on 
imports  to  cover  demand.  99.9%  of  imported  volumes  come  from  Russia,  transited  through 
Ukraine  (Figure  A.  25).  Since  2015,  when  operation  began  at  a  small  pipeline  connecting  the 
Romanian  transmission  system  (Iasi)  with  the  Ungheni  region  in  Moldova,  small  volumes  are 
being  imported  from  Romania.  However,  as  this  pipeline  does  not  reach  the  Moldovan 
transmission system, imports from Romania to the whole market are not possible.   

Annual consumption in the right bank of Dniester River is around 1 bcm/yr. In the Transnistria 
region 1.7 bcm/yr are consumed (60% used for electricity generation in the Cuciurgani TPP), all 
covered with imports of Russian gas100. 

99 Reported data from the Bureau of Statistics does not include Transnistria 
100 Current  situation  and  future  perspective  of  LNG  in  Moldova,  2018.  The  2nd  meeting  of  the  Eastern  Partnership 
Energy Panel. Available online at: https://ec.europa.eu/energy/sites/ener/files/documents/moldova_-_lng_situation.pdf 
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Figure A. 25: Evolution of natural gas supply and demand in Moldova (without Transnistria) 

Source: Eurostat Statistics Database 

The existing contract with Russia expires in December 2019100. Figure A. 26 presents the border 
prices of imported gas, for the period of 2010 – 2018. 

Figure A. 26: Evolution of average import prices in Moldova 

Source: National Agency for Energy Regulation (2018). Report on Activities 2018.  

In its Energy Strategy to 2030, prepared in 2012, the Government of Moldova set LNG imports 
and development of gas storage as an alternative for enhancing security of supply. However, no 
concrete targets were set in this regard (the AGRI project is mentioned as a potential source that 
should be monitored)101. 

Figure A. 27 presents the 2017 balance of the natural gas sector in Moldova. Gas is primarily 
used for  the generation of  electricity  and heat,  at  CHP  and district  heating  plants. To a  lesser 
extent, it is used for residential heating. 

 Energy  Strategy  of 

101
the 
http://komorasns.cz/assets/attachments/EnStrategy-MOLD-draft310512.pdf 

the  Republic  of  Moldova 

to 

year  2030 

(2012),  available  at: 

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Figure A. 27: Natural gas balance in Moldova (2017) (without Transnistria) 

Source: National Bureau of Statistics of the Republic of Moldova, Energy Balance 2017102 

Due to the large use of gas for heat generation, and for heating of households, gas demand in 
Moldova is highly seasonal. 

A1.5.3. Natural gas prices 
End-user gas prices are regulated in Moldova, set by the National Agency for Energy Regulation 
(ANRE).  ANRE  has  defined  separate  tariffs  for  the  use  of  the  transmission  and  distribution 
systems, and end-user prices for different categories of consumers (Table A. 9). 

Both  transmission  and  distribution  tariffs  are  defined  using  a  postage-stamp  approach.  The 
current tariffs for transmission is set at 1.62 €/1000 m3, and for distribution 142103 €/1000 m3 (split 
10  €/1000  m3  for  use  of  high  pressure  pipelines,  26  €/1000  m3  for  use  of  medium  pressure 
pipelines, and 106 €/1000 m3 for use of low pressure pipelines)104. 

Table A. 9: Indicative regulated end-user prices in Moldova (2017) 

Category 

Regulated price in €/1000 m3 
(excluding VAT) 

Residential (for heating) – consumption up to 30 m3 per month 

Residential (for heating) – consumption over 30 m3 per month 

Local heating plants and CNG stations – connected to 
transmission 

Local heating plants and CNG stations – connected to medium 
pressure distribution 

CHP and district heating plants 

Source: National Agency for Energy Regulation Decision No 88/2018 

236 

245 

160 

225 

201 

102 Converted to mcm using a GCV of 10.0474 kWh/m3 (https://www.moldovatransgaz.md/en/clients/quality) 
103 Average tariff that varies for different distribution systems 
104 ANRE Decision No 88/2018, available at: 
http://anre.md/files/Gaze_naturale/caculov/29112018/Hot%C4%83r%C3%A2rea%20ANRE%20nr.88%20din%2018.0
3.%202018.pdf 

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A1.5.4. Natural gas infrastructure 
The  length  of  the  main  sections  of  the  Moldovan  gas  transmission  system  is  656  km.  The 
system includes connections with Ukraine and Romania, to supply the local gas market, as 
well as to transit gas through the country (Figure A. 28).  

The main connections of the transmission system with Ukraine include105: 

  Ananiev-Cernăuți-Bogorodcianî  (АCB)  pipeline,  with  185  km  length  and  9.1  bcm/yr 

capacity that crosses the northern part of Moldova to re-enter Ukraine 

  3  pipelines  sections  that  connect  Ukraine  –  Moldova  –  Romania  with  aggregate 

capacity of 34.6 bcm/yr, namely: 

o  Ananiev-Tiraspol-Ismail  (ATI)  pipeline,  with  63  km  length  and  20  bcm/yr 

capacity 

o  Șebelinca-Dnepropetrovsk-Krivoi  Rog-Ismail  (ȘDKRI),  with  92  km  length  and 

7.9 bcm/yr capacity 

o  Razdelinaia-Ismail (RI), with 92 km length and 7.9 bcm/yr capacity   

  Odesa-Chișinău (ОCh) pipeline, with 44 km length and 1.3 bcm/yr capacity  

Figure A. 28: Gas transmission system in Moldova 

Sources: ENTSOG, Moldovatransgaz  

105 Infrastructure of transmission system of Moldovatransgaz. Available online at: 
https://www.moldovatransgaz.md/en/activities/transmission/map 

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Romania  and  Moldova  are  currently  connected  with  a  43  km  long  pipeline  connecting  Iasi 
(Romania) with Ungheni (Moldova). In February 2019, construction works started for extending 
the pipeline up to Chisinau, with total length 120 km and capacity of 1.5 bcm/yr.  

A1.5.5. Market structure 
The  gas  market  of  Moldova  is  practice  monopolistic.  The  vertically  integrated  company 
Moldovagaz 106  (50%  Gazprom,  36.6%  state-owned,  13.4%  authorities  in  Transnistria), 
undertakes  the  imports  of  Russian  gas,  wholesale  supply,  the  majority  of  retail  sales,  and  is 
responsible  for  gas  transmission  and  distribution,  through  its  subsidiaries.  The  small  volumes 
supplied to the region of Ungheni are being imported through a separate entity, the state-owned 
Energocom107. 

Moldovatransgaz (100% subsidiary of Moldovagaz) is the operator of the national transmission 
system. Tiraspoltransgaz operates the system in Transnistria. Eurotransgaz108 (subsidiary of the 
Romanian TSO Transgaz) is the operator of the Iasi - Ungheni pipeline. 

On  a  retail  level,  there  are  overall  25  distribution  license  holders,  12  of  which  Moldovagaz 
subsidiaries, that hold around 70% of the distribution networks. 

ANRE  is  regulating  the  gas  sector,  responsible  approving  regulations,  monitoring  market 
operation, setting tariffs and issuing licenses. 

Figure A. 29: Key stakeholders in Moldovan gas supply chain 

A1.5.6. Regulatory framework 
The gas sector in Moldova is governed by the Gas Law, no. 108/2016, entered into force in July 
2016. The Law transposes the vast majority of the 3rd Energy Package.  

In 2016,  ANRE  approved  the  Regulation  on  Access to the  Natural Gas Transmission  Network 
and  Congestion  Management  (Decision  no.  321/2016  of  13rd  December  2016).  Additional 
secondary legislation, to implement the 3rd Energy Package and EC Network Codes on Gas are 
under development.   

106 Moldova has received derogation from TSO unbundling, in compliance with Directive 2009/73/EC, until January 1 st 
2020  
107

Infrastructure:  Moldova  starts  gas 

imports 

(2015).  Available  at: 

from  Romania 

 Ministry  of 

https://mei.gov.md/en/content/moldova-starts-gas-imports-romania 
108 Formerly state-owned Vestmoldtransgaz, that was bought by Transgaz in 2018 

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Table A. 10 below, provides an outline of the key regulatory framework provisions related to the 
overall market operation, transmission system and off-grid supplies of LNG.  

Table A. 10: Overview of regulatory framework in Moldova (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Licensing of gas stakeholders 

Law of the Republic of Moldova about Natural Gas 
(2016) 

  Procedures foreseen in the Gas Law. 
Licensees are issued by ANRE  

Eligibility of final consumers to choose supplier   

Transparent and non-discriminatory third-party 
access on the transmission system 

 

All consumers are allowed to switch suppliers 
(not in practice as supply and transmission are 
still bundled) 

Rules for access to transmission have been 
approved by ANRE. However, model contracts 
are not published by the TSO 

Rules for access to storage  

Unbundling of system operators 

Transmission system operation 

Establishment of capacity allocation 
mechanisms 

  N/A 
  Derogation until 1/1/2020 

 

Capacity at IPs is offered on pro-rata basis. 
Only annual (up to 5 years) and monthly 
capacity is offered 

Establishment of congestion management 
procedures 

  Capacity surrender and secondary market is 

foreseen 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

 

Transgaz Romania and Vestmoldtransgaz have 
reportedly signed an interconnection 
agreement (commercial provisions not 
published) 
Interconnection agreement between Moldova 
and Ukraine is under negotiation  

Definition of tariffs at cross-border entry/exit 
points 

Publication of gas technical specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

points are set 

  No specific tariffs for entry/exit interconnection 
  Published by Moldovatransgaz in its website 
Required by the Gas Law, but no balancing 
rules implemented yet. Nominations and 
allocation are only on monthly basis 

 

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A1.6. Ukraine 
A1.6.1. Role of natural gas in the energy mix 
Natural gas is a key fuel in the energy mix of Ukraine (Figure A. 30). With a share of 27%, it is the 
second largest source in the country’s total primary energy supply. In total final consumption, gas 
is the dominant fuel, as it is the main source of heating in the residential sector.    

Figure A. 30: Natural gas in the energy mix of Ukraine (2017) 

Total Primary Energy Supply 

Total Final Consumption 

Source: State Statistics Service of Ukraine, Energy Balance 2017 

A1.6.2. Natural gas supply & demand 
Natural  gas  demand  in  Ukraine  is  currently  at  the  level  of  32-33  bcm/yr 109  (Figure  A.  31). 
Indigenous production of gas in Ukraine is high, and has remained stable during the last three 
decades, at a plateau of around 20 bcm/yr. Gas is imported to cover remaining demand. In the 
past, all gas imports in Ukraine were sourced from Russia, until in 2013 imports from EU markets 
began. In November 2015, imports from Russia ceased, and Ukraine has been importing gas only 
from European suppliers.   

Imports from the EU are mainly carried out though Slovakia, the rest coming through Poland and 
Hungary  (Figure  A.  32).  With  the  existing  transmission  system  infrastructure,  import  capacity 
depends  partially  on  flow  of  Russian  gas  transits.  According  to  Naftogaz,  in  case  there  is  a 
disruption to transit of Russian gas, not all the capacities at the western border of the country can 
be used to import gas from Europe110.  

109 The reported figures do not include gas supply and demand for Crimea and part of Donbass region 
110 https://en.interfax.com.ua/news/economic/584272.html 

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Figure A. 31: Evolution of natural gas supply and demand in Ukraine 

Source: Naftogaz website, Facts & Figures 

Figure A. 32: EU gas imports to Ukraine by entry point 

Source: Naftogaz website, Facts & Figures 

Gas production is carried out mainly by subsidiaries of Naftogaz, Ukrgasvydobuvannya (UGV), 
Ukrnafta and Chornomornaftogaz (ChNG) (79% in 2018), with the remaining volumes extracted 
by private producers.  

Gas  imports  are  mainly  carried  out  by  Naftogaz  (over  66%  in  2018),  that  is  buying  gas  from 
several exporters (RWE, Axpo Trading, DufEnergy, ENGIE, Uniper Global and others). Private 
traders have also been engaged in gas imports, such as ERU Trading, Promenergo Resource, 
Socar Ukraine, Trafigura Ukraine. 

Figure A. 33 presents the 2018 balance of the natural gas sector in Ukraine. Natural gas is mainly 
used in households, and at district heating and cogeneration plants.  

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Figure A. 33: Natural gas balance in Ukraine (2018) 

Source: UTG 

The demand projections included in the ten-year development plans of UTG (Figure A. 34) and 
the SSO (Figure A. 35) show similar decrease in the future consumption of gas in the Ukrainian 
market. However, there is a different outlook concerning the forecasts of indigenous production. 
According  to  UTG,  production  will  cover  almost  100%  of  demand  after  2027,  while  SSO 
projections are more conservative.  

Figure A. 34: Demand & Supply forecasts for Ukrainian gas market – UTG 

Source: UTG, TYNDP 2019 – 2028  

 Figure A. 35: Demand & Supply forecasts for Ukrainian gas market – SSO 

Source: SSO, Development Plan 2020 – 2029  

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A1.6.3. Natural gas prices 
End-user prices for households, religious organizations (very small consumption), district heating 
and cogeneration plants, and state organizations are regulated. The regulated prices are set by 
the Cabinet of Ministers. The prices include four components: Naftogaz selling price, transmission 
price,  distribution  price  (for  retail  consumers)  and  delivery  price.  The  regulated  price  for 
households is provided in Figure A. 36 below. 

Figure A. 36: Final retail price for households (November 2018 – April 2019) 

Source: Naftogaz, Prices for natural gas 

All other consumers source gas in the market at unregulated prices. On wholesale level, gas is 
traded  at  the  Ukrainian  Energy  Exchange.  Traded  priced  at  the  Exchange  have  decreased 
considerably the past months (Figure A. 37).  

Figure A. 37: Average monthly natural gas prices at Ukrainian Energy Exchange 

Source: Ukrainian Energy Exchange 

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For the  use  of  the transmission  system, the tariffs  are  set  by the  National  Energy  and  Utilities 
regulatory Commission, following proposal by the TSO. Depending on the type of entry/exit points 
of the system, different tariffs are set111: 

  For  the  cross-border  entry/exit  points,  entry  and  exit  tariffs  were  introduced  as  of 
1/1/2019. The entry tariff is common at all points, 5.6 €/1000 m 3, while the exit tariff 
ranges from 10 €/1000 m3 to 15.5 €/1000 m3. 

  For exits to consumers directly connected to the transmission system, a tariff of 20.9 

€/1000 m3 is set. 

  For  exit to  distribution systems, the tariff depends on  the  territory  which  is  supplied, 
and  may  range  from  very  low  tariffs  (0.07  €/1000  m 3,  for  exit  to  the  DSO  PJSC 
"Mykolaivgaz") up to high ones (19.8 €/1000 m3, for exit to the DSO LLC "Spektrgaz"). 

A1.6.4. Natural gas infrastructure 
The main transmission pipelines of the Ukrainian system exceed 35,000 km. The system was 
designed  as  an  integral  part  of  the  former  Soviet  Union  unified  gas  supply  system,  the 
specification  to  provide  reliable  gas  delivery  both  to  internal  consumers  and  transit  to  the 
European gas market.  

Ukrtransgaz operates one of Europe’s leading networks of underground gas storage (UGS) 
facilities. Today, the company operates 12 underground storage facilities (including 1 in the 
occupied territory) with total design working volume of up to 31 bcm112. It should be noted that 
the actual technical characteristics of the storages have changed and should be verified. 

The transmission system and the distribution systems are very developed and cover all Ukrainian 
regions. However, in 2014 there were 35 towns, 111 townships and 2,698 villages non-connected 
to natural gas grid as well as without LPG supply, creating potential interest for off-grid supplies 
of LNG.  

Table A. 11: Gasification Coverage in Ukraine (2014) 

Number 

Natural 
Gas 
exclusively 

Towns 

Townships 

442 

828 

117 

164 

Rural Villages 

27412 

4127 

% 

26.5 

19.8 

15.1 

Natural 
gas and 
LPG 

% 

LPG 
exclusively 

% 

Without 
supply 

% 

271 

398 

61.3 

48.1 

19 

155 

4.3 

35 

7.9 

18.7 

111 

13.4 

10606 

38.7 

9981 

36.4 

2698 

9.8 

Source: State Statistical Service, Statistical Bulletin on Gas Distribution, 2014  

Apart from the entry points in the eastern part of the country, and the corresponding exit points 
to  Poland,  Slovakia,  Hungary,  Romania  and  Moldova,  which  are  being  used  for  transit  of 

111 Ukrtransgaz, Tariffs & Prices, Available at: http://utg.ua/en/utg/business-info/tariffs.html 
112 Naftogas, Facts & Figures, Available at: http://naftogaz-europe.com/factsandfigures/en/factsandfigures 

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Russian  gas,  the  Ukrainian  system  also  has  entry  capacity  from  Poland,  Slovakia  and 
Hungary, used to import gas from the EU. 

Figure A. 38: Entry Interconnection Points from EU to Ukraine 

Sources: ENTSOG, Ukrtransgaz 

Following  the  adoption  of  the  amendments  to  the  Customs  Code,  Ukraine  is  now  able  to  run 
backhaul operations; that is, replace gas on a certain pipeline with no need to receive it on specific 
cross-border  points.  Such  operations,  called  a  “virtual  reverse  flow”,  are  possible  under 
commercial supply contracts and interconnection agreements of TSOs113. 

New projects are being developed, aiming to increase the potential of Ukraine for diversified gas 
supplies.  Ukrtransgaz  and  Transgaz  of  Romania  have  agreed  on  the  reconstruction  of  gas 
metering station Isaccea-1, at the Transit-1 pipeline section of the Trans-Balkan Pipeline allowing 
to  increase  the  accuracy  of  gas  metering  and  bidirectional  flow  in  the  interconnection  point. 
Ukrtransgaz conducted in March – April 2018 a non-binding market demand assessment among 
the participants of Ukrainian and EU market for the firm capacity of Transit-1 pipeline in direction 
RO-UA. 5 bcm/yr of annual capacity was offered to market participants, with the results showing 
much  higher  interest.  As  the  next  step,  Ukrtransgaz  plans  to  conduct  a  binding  open  season 
procedure,  making  available  capacities  to  market  participants  starting  from  the  beginning  of 
2020114. 

113 Ukraine’s Gas Sector Reform: A Future Win-Win for Ukraine and Europe, Dixi Group, 2017 
114  Ukrtransgaz 
demand-assessment-for-entry-capacities-to-ukraine-from-romania.html 

  announcement 

(2018),  http://utg.ua/en/utg/media/news/2018/successfully-conducted-market-

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The Ukrainian Government has also explored the possibility of constructing an LNG terminal in 
the  Black  Sea,  located  at  the  Yuzhny  Port  near  Odessa.  Although  discussions  for  such  an 
infrastructure  began  in  1993,  the  most  recent  effort  for  developing  the  LNG  Terminal  was 
launched  by  the  Ukrainian  leadership  in  late  2010,  undertaken  by  the  state-owned  ‘National 
Project LNG Terminal’. The prefeasibility and technoeconomic studies implemented, concluded 
to a phased development of the terminal, with initial installation of an FSRU (capacity 5 bcm/yr), 
and  subsequent  construction  of  an  on-shore  LNG  terminal  (capacity  10  bcm/yr).  The  project 
ceased  in  2014,  because  the  ‘National  Project  LNG Terminal’ reached  a  negative  bottom  line, 
and  the  State  Agency  for  Investment  and  National  Projects  of  Ukraine  collapsed.  The  main 
challenge that the project faced was that the Turkish authorities did not agree for passage of LNG 
vessels through the Bosporus Straits. 

Furthermore, there have been plans for the interconnector Drozdovichi – Bilche Volytsia between 
Poland and Ukraine aiming to import of gas primarily from the Polish LNG terminal in Świnoujście. 
The  Ukrainian  part  was  designed  with  pipeline  length  of  99.3  km,  capacity  of  8  Bcm/y  (23.8 
mmscm/d)  at  the  direction  Poland  to  Ukraine,  and  capacity  7  Bcm/y  (20.8  mmscm/d)  at  the 
reverse direction115. It is noted that according to UTG the pipeline is not included in the 2020 – 
2029 TYNDP of Ukraine. 

A1.6.5. Market structure 
The Ukrainian gas market is structured into two segments: a regulated segment, that includes 
gas  supply  to  households,  district  heating  plants,  CHP,  religious  organizations  and  state 
organizations, and a non-regulated segment that includes all other types of consumers. 

The  wholesale  part  of  gas market  functions  in  accordance  with  the  Public  Service Obligations 
(PSO) stipulated in the Law on Natural Gas Market, and the Resolution of the Cabinet of Ministers 
No 867 of October 19, 2018 that oblige: 

  State  gas  producers  (Naftogaz  subsidiaries)  Ukrgasvydobuvannya  (UGV)  and 
Chornomornaftogaz  (ChNG)  to  sell  gas  to  Naftogaz  (and  for  the  latter  to  buy  it)  for 
residential market needs at a regulated price (upstream sector); 

  Naftogaz to sell gas directly to district heating companies (and for the latter to buy it) 

for all needs at a regulated price (wholesale sector); 

  Naftogaz  to  sell  gas  to  retail  suppliers  under  PSO  (and  for  the  latter  to  buy  it)  for 

residential market needs at a regulated price (retail sector). 

Figure A. 39 below presents the structure of the regulated segment of the market. 

115  Ukrtransgaz 
planuyut-rozpochati-proektn-roboti-po-nterkonektoru-ua-pl.html 

  announcement  (2016),  http://utg.ua/utg/media/news/2016/06/polskij-ta-ukranskij-operatori-gts-

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Figure A. 39: Structure of Ukrainian Gas Market Regulated Segment 

The non-regulated segment of the market is competitive. Private producers are free to sell gas at 
the Ukrainian Energy Exchange, and wholesale suppliers (traders) import gas from the EU and 
trade gas at the Exchange or sign bilateral contracts for supply. There are 548 supply licensees 
registered with NEURC. On distribution level, there are 46 DSOs, 44 of which are also holding a 
supplier licence. 

Operation of the underground storage facilities is currently carried out by Ukrtransgaz (Naftogaz 
subsidiary).  As  of  1/1/2020,  operation  of  the  transmission  system  is  carried  out  by  a  new 
independent operator, “TSO of Ukraine” LLC.   

NEURC  is  regulating  the  gas  sector,  responsible  approving  regulations,  monitoring  market 
operation, setting transmission and distribution tariffs and issuing licenses. Regulated end-user 
prices are set by the Cabinet of Ministers 

Figure A. 40: Key stakeholders in Ukrainian gas supply chain 

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A1.6.6. Regulatory framework 
The Law of Ukraine on the Natural Gas Market of 2015 (No 102/2015, 23.09.2015) is the primary 
legislation governing the Ukrainian gas sector. The Law transposes the most provisions of the 3rd 
Energy Package116. 

Key secondary legislation was developed in 2015, with adoption of the grid codes for transmission 
(NEURC Res. No 2494, 30.09.2015), distribution (NEURC Resolution No 2493, 30.09.2015) and 
storage (NEURC Resolution No 2495, 30.09.2015) by NEURC, that have been revised several 
times until today. The latest revisions of the transmission grid code (NEURC Resolutions No 1437 
in  2017,  and  No  1916  in  2018)  established  the  requirements  for  developing  a  daily  balancing 
regime in the transmission and distribution systems. 

Table A. 12: Overview of regulatory framework in Ukraine (: covered, : partly covered, : ongoing 
procedure, : not covered) 

Overall market operation 

Law governing the gas sector 

Licensing of gas stakeholders 

Law of Ukraine on the Natural Gas Market (2015) 
  Procedures foreseen in the Gas Law. 
Licensees are issued by NEURC  

Eligibility of final consumers to choose supplier   

Transparent and non-discriminatory third-party 
access on the transmission system 

 

Consumers are eligible to choose supplier. All 
suppliers in the regulated segment must sell 
gas at the regulated prices 

Rules for access to transmission have been 
approved by NEURC. Model contracts have 
been published by the TSO and transparent 
information is provided 

Rules for access to storage  

Unbundling of system operators 

Transmission system operation 

Establishment of capacity allocation 
mechanisms 

Establishment of congestion management 
procedures 

Existence of transparent interconnection 
agreements with neighbouring TSOs 

  Rules for access approved by NEURC 
  Unbundling procedure is in progress 

 

 

 

Auctions are being applied on the Ukrainian 
side of interconnection points (not in a booking 
platform) 

Long-term use-it-or-lose-it mechanism is 
foreseen. A secondary capacity market is in 
operation 

The TSO has signed Interconnection 
Agreements with HU, PL, RO, SK (not on all 
trans-border points), but they are not published. 
Negotiations are ongoing for a new agreement 
with RO and with MD 

Definition of tariffs at cross-border entry/exit 
points 

  The TSO has defined entry/exit tariffs at 

interconnection points 

116  Energy  Community,  Ukraine  Secondary 
community.org/implementation/Ukraine/secondary.html 

legislation  status:  Gas,  Available  at:  https://www.energy-

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Publication of gas quality specifications 

Transparent procedures for operation of the 
system (nomination, allocation, balancing) 

  Published by UTG in its website  

 

Procedures for nomination, allocation and 
balancing have been established. The 
balancing platform began operation 

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Annex 2: Netback Analysis – Gas-to-Gas Competition 

A2.1. Netback  analysis  in  case  of  regasified  LNG  supplied  via 
pipeline from neighbouring EU LNG Terminals 
A2.1.1. Analysis approach 
Figure A. 41 outlines the netback analysis for deriving the competitive LNG price, in the case of 
regasified  LNG,  sourced  from  neighbouring  EU  terminals  and  supplied  to  the  Eastern  Partner 
countries via pipelines.  

Figure A. 41: Netback analysis to estimate competitive LNG price at the source (LNG Terminal), for 
regasified LNG delivered to the Eastern Partner country by pipeline 

The  starting  point  (Step  1)  for  the  analysis  is  the  wholesale  gas  price  in  the  Eastern  Partner 
country in question. In the countries where prices for all consumers are regulated, the price for 
large consumers, excluding transmission costs, is applied. From this price, all costs to arrive from 
the  LNG  source  (terminal)  are  sequentially  estimated  and  subtracted:  costs  for  entry  in  the 
transmission system of the Eastern Partner country (Step 2), cross-border charges for the gasified 

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LNG to get to the  Eastern Partner  country  border (Step 3), the  charges at the  interconnection 
between LNG terminal and transmission system (Step 4), the LNG terminal charges for unloading, 
storage and regasification (Step 5).   

The resulting LNG price from the netback analysis is the price that needs to be compared to the 
regional price of spot LNG deliveries to the terminal to ascertain whether LNG is competitive to 
prices of existing gas sources in the Eastern Partner country.   

A2.1.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
supply of regasified LNG from neighbouring LNG terminals is an applicable option for Moldova 
and Ukraine. In particular117: 

  For  Moldova,  supplies  of  regasified  gas  from  the  Świnoujście  (Poland),  Klaipeda 
(Lithuania), Revythoussa (Greece) and Krk (Croatia) LNG terminals are examined.  

  For  Ukraine,  supplies  of  regasified  gas  from  the  Świnoujście  (Poland),  Klaipeda 
(Lithuania), Revythoussa (Greece) and Krk (Croatia) LNG terminals are examined. 

The capacity availability at the examined terminals is as follows118: 

  At  the  Revythoussa  terminal,  technical  regasification  capacity  is  17.1  mcm/d,  while 
available capacity for Gas Year 2019 (01/10/2018 – 30/09/2019) was 44% (7.5 mcm/d), 
and for the current Gas Year 2020 (01/10/2018 – 30/09/2019) it is 48% (8.2 mcm/d). 

  At  the  Klaipeda  terminal,  technical  regasification  capacity  is  10.5  mcm/d,  while 
available capacity for Gas Year 2019 was 52% (5.5 mcm/d), and for the current Gas 
Year 2020 it is 80% (8.4 mcm/d). 

  At the Świnoujście terminal, technical regasification capacity is 13.4 mcm/d, while  all 
capacity  has  been  booked  by  PGNiG  until  2034.  With  the  upcoming  capacity 
expansion, technical capacity will increase to 20.5 mcm/d. 

Access  to  the  terminal  also  depends  on  the  availability  of  slots  for  unloading  that  are  defined 
through monthly and annual nomination procedures. 

The calculations for the netback analysis steps are described in the sections below. 

A2.1.3. Step  1:  Definition  of  wholesale  gas  prices  in  Eastern  Partner 
countries 
The wholesale gas prices used as a starting point in the analysis are based on the current prices 
in each Eastern Partner country. 

117 Other potential supply options include the Marmara Ereglisi terminal in Turkey and the planned Alexandroupolis 
FSRU in Greece and Gdansk FSRU in Poland. The netback analysis of these options would wield similar results with 
the examined terminals. 
118 Source: Websites of DESFA (Revythoussa), Polskie LNG (Świnoujście), Klaipedos Nafta (Klaipeda) 

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In Moldova, the regulated price set by ANRE, for entry into the gas transmission system is used119, 
i.e. 151.5 EUR/1000 m3.  

In Ukraine, the price of the wholesale market is a mix of the import price of EU supplies and the 
price of indigenously produced gas. As Ukrainian gas is on average cheaper than the imports, it 
is expected that supplies of regasified LNG will compete with supplies from EU. For this reason, 
in our netback analysis we use the average price of imported gas, including the entry tariff to enter 
the Ukrainian market. As import prices are fluctuating considerably (Figure A. 42), we examine 3 
scenarios for the average level of import prices in Ukraine, corresponding to the average (241 
EUR/1000 m3), average for winter season (257 EUR/1000 m3) and minimum (198 EUR/1000 m3) 
price for the period Q1 2017 – Q2 2019. 

Figure A. 42: Average quarterly import price in Ukraine (including entry tariff)120 

Source: NEURC Monitoring Report, Q2 2019 

A2.1.4. Steps 2-3: Calculation of cross-border charges 
The routes used to transport regasified LNG from the neighbouring terminals to Ukraine and 
Moldova involve, in some cases, the same interconnection points.  

119 Source: Moldovan National Agency for Energy Regulation Decision No 88/2018 
120 Conversion from UAH to EUR using the average exchange rate of the corresponding quarter 

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Table A. 13 below presents the tariffs of the interconnection points covering all the routes from 
each  LNG  terminal  up  to  the  Eastern  Partners’  markets.  Where  necessary,  conversion  from 
energy units to volumetric units was carried out using the GCV presented in Annex 7. For projects 
under development (GIPL pipeline, Ungheni – Chisinau Pipeline, upgrade of IP Dravaszerdahely 
linked with development of Krk LNG terminal) assumptions based on public information have been 
made. 

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Table A. 13: Tariffs at interconnection points relevant to the regasified LNG routes 

Interconnection Point 

IP Hermanovice 

GIPL Pipeline 

IP Isaccea (Romania) 
- Orlovka (Ukraine) 

IP Negru Voda I 
(Romania) / Kardam 
(Bulgaria) 

IP Kulata (Bulgaria)/ 
Sidirokastron(Greece) 

IP Beregdaróc 
(Hungary) / Beregovo 
(Ukraine) 

IP Dravaszerdahely 

IP Oleksiivka 

IP Ungheni131 

Entry Ukraine121 
Exit Poland122 
(Interruptible) 
Entry Poland123 
Exit Lithuania124 
Entry Ukraine121 
Exit Romania125 
Entry Romania125 
Exit Bulgaria (Capacity 
charge)126 
Exit Bulgaria 
(Commodity charge)126 
Entry Bulgaria 
(Capacity charge) 126 
Entry Bulgaria 
(Commodity charge) 126 
Exit Greece127 
Entry Ukraine121 
Exit Hungary 
(Interruptible)128 
Entry Hungary128 
Exit Croatia129 
Entry Moldova130 
Exit Ukraine121 
Entry Moldova 
Exit Romania 

Tariff 

5.7 

Unit 
EUR/1000 m3 

1,847.6 

EUR/1000 m3/d/yr 

2,929.5 
1,993.2 

5.7 
1,299.8 
1,668.1 

EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 
EUR/1000 m3 
EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 

1,086.4 

EUR/1000 m3/d/yr 

1.1 

EUR/1000 m3 

1,680.2 

EUR/1000 m3/d/yr 

Capacity 

6.4 mcm/d 
(interruptible) 

5.2 mcm/d 

4.1 mcm/d 
(interruptible) 

6.9 mcm/d 
(interruptible) 

1.1 

EUR/1000 m3 

4 mcm/d 

2,997.6 
5.7 

EUR/1000 m3/d/yr 
EUR/1000 m3 

1,053.0 

EUR/1000 m3/d/yr 

1,260.4 

1,697.9 
1.7 
15.7 
1.7 
1,299.8 

EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 
EUR/1000 m3 
EUR/1000 m3 
EUR/1000 m3 
EUR/1000 m3/d/yr 

19.5 mcm/d 
(interruptible) 

6.6 mcm/d 
(interruptible) 

24.9 mcm/d 

4.1 mcm/d 

121 Source: Ukrtransgaz Price List 
122 Source: Gaz System Price List 
123  The  existing  exit  tariff  in  Poland  has  been  assumed  (Gaz  System  tariff  methodology  https://en.gaz-
system.pl/fileadmin/centrum_prasowe/Aktualnosci/2019/20190905_Taryfa/The_Tariff_for_Gas_Transmission_Servic
es_No._13_-_searchable_version_.pdf) 
124 The exit tariff at Kiemenai has been assumed, increased by 11% (based on GIPL promoter estimate in its Investment 
Request: 
https://acer.europa.eu/Official_documents/Acts_of_the_Agency/Individual%20decisions/ACER%20Individual%20Deci
sion%2001-2014%20on%20GIPL.pdf) 
125 Source: Transgaz Price List 
126 Source: Bulgartransgaz Price List 
127 Source: DESFA Price List 
128 Source: FGSZ Price List 
129 The tariff published in Croatia LNG Open Season has been used (http://www.plinacro.hr/default.aspx?id=855) 
130 Source: Moldovan National Agency for Energy Regulation Decision No 88/2018 
131 The current tariffs on the Romanian and Moldovan systems have been assumed 

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It is noted that the calculation of cross-border charges is based on the current entry/exit tariffs of 
each  TSO.  Upcoming  revisions  of  the  tariffs  or  changes  due  to  the  increase  of  gas  volumes 
transported, are not taken into consideration. 

To  apply  the  tariffs  that  include  a  capacity  charge,  we  assume  a  peak  daily  requirement  for 
regasified LNG132: 

  For Ukraine, it is assumed that the annually transported volumes will be  1 bcm/yr. As 
winter daily demand of non-household consumers in Ukraine is 25%  higher than the 
average, the peak daily requirement for regasified LNG is estimated at  3.4 mcm/d. 

  For Moldova, it is assumed that the annually transported volumes will be 0.5 bcm/yr. 
It is assumed that winter daily demand is 20% higher than the average, and therefore 
the peak daily requirement for regasified LNG is estimated at 1.64 mcm/d.  

Table A. 14 presents the unit cross-border charges for each route to Ukraine (in EUR/1000 m3), 
corresponding to the peak daily gas requirement of 6.85 mcm/d. 

Table A. 14: Unit cross-border charges for regasified LNG routes of Ukraine 

Interconnection Point 

Tariff (EUR/1000 m3) 

Route: Poland -> Ukraine 

IP Hermanovice 

Exit Poland 
Entry Ukraine 

Aggregate for route: 

Route: Lithuania -> Poland -> Ukraine 

GIPL Pipeline 

IP Hermanovice 

Exit Lithuania 
Entry Poland 

Exit Poland 
Entry Ukraine 

Route: Greece -> Bulgaria -> Romania -> Ukraine 

Aggregate for route: 

IP Kulata (Bulgaria)/ 
Sidirokastron(Greece) 

IP Negru Voda I 
(Romania) / Kardam 
(Bulgaria) 

Exit Greece 
Entry Bulgaria 

Exit Bulgaria 

Entry Romania 

IP Isaccea (Romania) 
- Orlovka (Ukraine) 

Exit Romania 
Entry Ukraine 

Aggregate for route: 

Route: Croatia -> Hungary -> Ukraine 

IP Dravaszerdahely 

Exit Croatia 
Entry Hungary 

6.3 
5.7 
12.0 

6.8 
10.0 

6.3 
5.7 
28.9 

10.3 
6.9 

4.9 

5.7 

4.5 
5.7 
37.9 

5.8 
4.3 

132 It  is  noted  that  for  the  purposes  of  the  netback  analysis,  the  assumed  volumes  are  only  used  to  estimate  the 
difference between average and peak daily demand, to apply capacity charges. As unit costs are examined, the actual 
availability of capacity along the route is not examined.  

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IP Beregdaróc 
(Hungary) / Beregovo 
(Ukraine) 

Exit Hungary 

Entry Ukraine 

Aggregate for route: 

3.6 

5.7 

19.4 

Table A. 15 presents the unit cross-border charges for each route to Moldova (in EUR/1000 m3), 
corresponding to the peak daily gas requirement of 1.64 mcm/d. 

Table A. 15: Unit cross-border charges for regasified LNG routes of Moldova 

Interconnection Point 

Tariff (EUR/1000 m3) 

Route: Poland -> Ukraine -> Moldova 

IP Hermanovice 

IP Oleksiivka 

Exit Poland 
Entry Ukraine 
Exit Ukraine 
Entry Moldova 

Route: Lithuania -> Poland -> Ukraine -> Moldova 

Aggregate for route: 

GIPL Pipeline 

IP Hermanovice 

IP Oleksiivka 

Exit Lithuania 
Entry Poland 
Exit Poland 
Entry Ukraine 
Exit Ukraine 

Entry Moldova 

Aggregate for route: 

6.1 
5.7 
15.7 
1.7 
29.2 

6.6 
9.6 
6.1 
5.7 
15.7 

1.7 
45.4 

Route: Greece -> Bulgaria -> Romania -> Ukraine -> Moldova 
9.9 
6.7 
4.7 

Exit Greece 
Entry Bulgaria 
Exit Bulgaria 

IP Kulata (Bulgaria)/ 
Sidirokastron(Greece) 

IP Negru Voda I 
(Romania) / Kardam 
(Bulgaria) 

IP Ungheni 

Entry Romania 

Exit Romania 
Entry Moldova 

Aggregate for route: 

Route: Croatia -> Hungary -> Ukraine -> Moldova 

IP Dravaszerdahely 

IP Beregdaróc 
(Hungary) / Beregovo 
(Ukraine) 

IP Oleksiivka 

Exit Croatia 
Entry Hungary 
Exit Hungary 

Entry Ukraine 

Exit Ukraine 
Entry Moldova 

Aggregate for route: 

5.5 

4.3 
1.7 
32.7 

5.6 
4.1 
3.5 

5.7 

15.7 
1.7 
36.3 

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A2.1.5. Step 4: Definition of entry charges from LNG terminal 
Table A.  16  below  presents the tariffs  of  the  entry  points  connecting  the  LNG terminals to the 
transmission systems. Where necessary, conversion from energy units to volumetric units was 
carried out using the GCV presented in Annex 7. For the LNG terminals in operation (Świnoujście, 
Klaipeda,  Revythoussa),  the  current  tariffs  applied  by  the  TSOs  are  used.  For  the  planned 
terminal in Krk, and the potential terminals in Ukraine and Georgia, assumptions have been made, 
based on public information.  

Table A. 16: Tariffs for entry from LNG terminal to transmission 

LNG terminal 

Świnoujście (entry to Polish system)122 
Klaipeda (entry to Lithuanian system)133 
Revythoussa (entry to Greek system)127 
Krk (entry to Croatian system)129 
Ukrainian terminal (entry to Ukrainian system)134 
Georgian terminal (entry to Georgian system)135 

Entry Tariff to 
transmission 
0 
112.2 
929.8 
2,176.5 

5.7 
6.1 

Unit 

EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 
EUR/1000 m3/d/yr 
EUR/1000 m3 
EUR/1000 m3 

As in the case of cross-border interconnection points, to apply the tariffs that include a capacity 
charge,  we  use  the  assumed  peak  daily  requirement.  The  calculated  charges  for  Ukraine  and 
Moldova are presented in Table A. 17 and Table A. 18 respectively. 

Table A. 17: Unit charges for entry from LNG terminal to transmission for routes of Ukraine 

LNG terminal 

Świnoujście (entry to Polish system)  
Klaipeda (entry to Lithuanian system) 
Revythoussa (entry to Greek system)  
Krk (entry to Croatian system)  

Tariff (EUR/1000 m3) 
0 
0.4 
3.2 
7.5 

Table A. 18: Unit charges for entry from LNG terminal to transmission for routes of Moldova 

LNG terminal 

Świnoujście (entry to Polish system)  
Klaipeda (entry to Lithuanian system) 
Revythoussa (entry to Greek system)  
Krk (entry to Croatian system)  

Tariff (EUR/1000 m3) 
0 
0.4 
3.1 
7.2 

133 Source: Amber Grid Price List 
134 The same entry tariff as interconnection points is assumed 
135 The transmission tariff is assumed 

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A2.1.6. Step 5: Definition of charges at EU LNG terminals 
Table A. 19 below presents the tariffs applied at the EU LNG terminals for unloading, storage and 
regasification. Where necessary, conversion from energy units to volumetric units was carried out 
using the GCV presented in Annex 7. For the LNG terminals in operation (Świnoujście, Klaipeda, 
Revythoussa), the current tariffs applied are used. For the planned terminal in Krk, assumptions 
have been made, based on public information.  

Table A. 19: Tariffs for the use (unloading, storage, regasification) of LNG terminals 

LNG terminal 

Tariff 

Unit 

Fixed component 

6,253.0 

EUR/1000 m3/d/yr 

Świnoujście136 

Variable component 

1.5 

EUR/1000 m3 

Send-out capacity 

13.4 mcm/d (to be 
increased to 20.5 
mcm/d with expansion 
programme) 

Klaipeda137 

Revythoussa127 

Krk129 

Fixed component 
Variable component 
Fixed component 
Variable component 
Variable component 

4,583.5 
1.5 
1,105.8 
1.4 
15.8 

EUR/1000 m3/d/yr 
EUR/1000 m3 
EUR/1000 m3/d/yr 
EUR/1000 m3 
EUR/1000 m3 

10.2 mcm/d 

17.1 mcm/d 

7.1 mcm/d 

As in the case of cross-border interconnection points, to apply the fixed component of the tariffs, 
we use the assumed peak daily requirement. The calculated unit tariffs for Ukraine and Moldova 
are presented in Table A. 20 and Table A. 21 respectively. 

Table A. 20: LNG terminal tariffs for the routes of Ukraine 

LNG terminal 

Świnoujście  
Klaipeda 

Revythoussa 
Krk  

Tariff (EUR/1000 m3) 
22.9 
17.2 

5.2 
15.8 

Table A. 21: LNG terminal tariffs for the routes of Moldova 

LNG terminal 

Świnoujście  
Klaipeda 
Revythoussa 

Krk  

Tariff (EUR/1000 m3) 
22.1 
16.6 
5.1 

15.8 

136 Source: Polskie LNG  
137 Source: Klaipedos Nafta Price List 

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A2.1.7. Results of analysis 
Ukraine 

The results of the netback analysis for Ukraine, concerning the maximum supply price of LNG at 
each of the examined EU receiving terminals, covering the 3 wholesale price scenarios (average, 
minimum, maximum) are presented in Table A. 22, Table A. 23 and Table A. 24 respectively.  

Table A. 22: Calculated maximum competitive LNG price at the source per receiving terminal, for 
average import price in Ukraine  

Item 

Source of regasified LNG 

Świnoujście  Klaipeda  Revythoussa 

Krk 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-12.0 

-0 

-22.9 

-28.9 

-0.4 

-17.2 

241 

-37.9 

-3.2 

-5.2 

-19.4 

-7.5 

-15.8 

206.0 

194.5 

194.7 

198.3 

Table A. 23: Calculated maximum competitive LNG price at the source per receiving terminal, for 
minimum import price in Ukraine  

Item 

Source of regasified LNG 

Świnoujście  Klaipeda  Revythoussa 

Krk 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-12.0 

-0 

-22.9 

-28.9 

-0.4 

-17.2 

198 

-37.9 

-3.2 

-5.2 

-19.4 

-7.5 

-15.8 

163.0 

151.5 

151.7 

155.3 

Table A. 24: Calculated maximum competitive LNG price at the source per receiving terminal, for 
maximum Ukrainian wholesale price  

Item 

Source of regasified LNG 

Świnoujście  Klaipeda  Revythoussa 

Krk 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-12.0 

-0 

-22.9 

-28.9 

-0.4 

-17.2 

257 

-37.9 

-3.2 

-5.2 

-19.4 

-7.5 

-15.8 

222.0 

210.5 

210.7 

214.3 

Moldova 

The results of the netback analysis for Moldova, concerning the maximum supply price of LNG at 
each of the examined EU receiving terminals, are presented in Table A. 25 below.  

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Table A. 25: Calculated maximum competitive LNG at the source per receiving terminal, for Moldova 

Item 

Source of regasified LNG 

Świnoujście  Klaipeda  Revythoussa 

Krk 

Wholesale gas price in Moldova (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-29.2 

0 

-22.1 

100.2 

-45.4 

-0.4 

-16.6 

89.2 

151.4 

-32.7 

-3.1 

-5.1 

110.7 

-36.3 

-7.2 

-15.8 

92.3 

A2.2. Netback  analysis  in  case  of  LNG  receiving  terminal  in 
Eastern Partner country 
A2.2.1. Analysis approach 
The netback analysis approach outlined in Figure A. 41 of Section A2.1 is applied, but in this case 
for regasified LNG sourced from an LNG terminal developed in an Eastern Partner country.  

A2.2.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, there 
is interest for the development of LNG receiving terminals in Georgia and Ukraine. The case of 
supplies of regasified LNG sourced from the Ukrainian terminal to the Moldovan market is also 
examined. 

As there are no up-to-date studies concerning the development of LNG infrastructure in either 
Georgia or Ukraine138, assumptions are made concerning the size of the terminals. In Ukraine, 
the  analysis  was  carried  out  assuming  the  development  of  an  FSRU  with  maximum  send-out 
capacity of 5 bcm/yr. In Georgia, a terminal with send-out capacity of 1 bcm/yr is assumed. For a 
facility of this size, detailed analysis is required to determine whether an on-shore terminal, FRSU 
or  FSU  solution  should be  selected,  as  availability  of  small-scale FSRUs  in the  market  is  very 
limited.    

In  the  absence  of  market  analysis  for  the  use  of  LNG  in  these  markets,  and  taking  into 
consideration that the unit costs of an LNG terminal are sensitive on its assumed utilization rate, 
in  order  to  conduct  this  high-level  analysis  we  examine  3  scenarios  for  each  terminal,  of  low 
(30%), medium (50%) and high (70%) utilization. 

Based on this context, the calculations for the netback analysis steps are described in the sections 
below. It is noted that when examining the in-country terminals is Georgia and Ukraine, Steps 2 
and 3 of Figure A. 41, concerning cross-border charges, are omitted. 

138 Studies for the development of an LNG terminal near Odessa were prepared in 2013, with very different supply & 
demand conditions in the Ukrainian market than the existing ones. 

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A2.2.3. Step  1:  Definition  of  wholesale  gas  prices  in  Eastern  Partner 
countries 
For Moldova and Ukraine, the gas prices defined in Section A2.1.3, for the case of supplies from 
the EU terminals, are applied.  

In the case of Georgia, the price of imported Azeri gas, for the commercial part of the market, 
amounts  to  200  EUR/  1000  m3,  and  has  ranged  from  165  –  245  EUR/  1000  m3 in  the  recent 
years139.  As  discussed  in Section  A1.4, gas  demand  in  the  coming  years  is  expected  to grow, 
while  the  existing  contracts  with  SOCAR  for  the  optional  and  additional  gas  are  expiring  after 
2025. The emerging supply gap should be covered by additional contracted gas volumes, that 
are  likely  to  be  more  expensive  that  current  supplies.  To  assess  different  cases  gas  price 
evolution, we examine 3 scenarios for the wholesale gas price in Georgia, corresponding to the 
current level of import price plus transmission tariff (206 EUR/1000 m3), a moderate (25%) price 
increase (256 EUR/1000 m3) and a high (50%) price increase (306 EUR/1000 m3). 

A2.2.4. Steps 2-3: Calculation of cross-border charges 
The only case for which Steps 2 and 3 apply is the supply of Moldova from the Ukrainian terminal. 
As defined in Sector A2.1.4, at the Oleksiivka interconnection point between the two countries, 
the exit tariff for Ukraine is 15.7 EUR/1000 m3 and the entry tariff for Moldova 1.7 EUR/1000 m3. 

A2.2.5. Step 4: Definition of entry charges from LNG terminal 
Estimates  for  the  tariffs  of  the  entry  points  connecting  the  LNG  terminals  to  the  transmission 
systems are made, based on the existing tariffs applied by the TSOs. In the case of Ukraine, we 
assume an entry tariff of 5.7 EUR/1000 m3, equal to the entry tariffs from interconnection points. 
In the case of Georgia, all potential costs required for the connection of the LNG receiving terminal 
to the transmission system (to allow reverse of the existing gas flow) are included in the terminal’s 
investment costs (Section A2.2.6), and therefore in the charge for use of the terminal. As an entry 
charge to the transmission system, we apply the existing transmission tariff of 6.1 EUR/1000 m3. 

A2.2.6. Step 5: Calculation of charges for Eastern Partners’ LNG terminals 
The  charges for  the  use  of the  potential  LNG  terminals  in  Ukraine  and  Georgia  are calculated 
using  benchmark  investment  costs  and  operation  expenses.  The cost for  using the terminal  is 
calculated  as  the  present  value  of  the  required  annual  revenues  (including  recovery  of  all  the 
investment costs and operating expenses and a return on the assets) per volume of regasified 
LNG, for the full duration of the terminal’s life cycle. The approach applied to calculate the charges 
is presented in Figure A. 43.  

139 Source: Department of Strategic Planning and Projects of GOGC 

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Figure A. 43: Calculation of charges at Eastern Partners’ LNG terminal 

The assumptions and benchmarks applied for calculating the LNG terminal charge in the case of 
Georgia are presented in Table A. 26. An approximation of the costs for a small on-shore terminal 
are used. These costs the required interventions to transmission the system, which would need 
to reverse of the current flows.  

Table A. 26: Values applied to calculate LNG terminal charge in Georgia 

Item 

Annual send-out capacity (bcm/yr) 
Cost for terminal (EUR) 
Life cycle of terminal (years) 
Expected rate of return on investment / discount 
rate 
Fixed operating expenses 
Variable operating expenses 
Assumed LNG opportunity cost (EUR/1000 m3) 
Terminal utilization factor 
LNG terminal charge (EUR/1000 m3) 

Value 
1 
170,000,000140 
30 (depreciation rate 3%) 

10% 

2.5% of CAPEX140 
1.1% of send-out 
220 
50% 
48.3 

30% 
80.5 

70% 
34.5 

The assumptions and benchmarks applied for calculating the FSRU charge in the case of Ukraine 
are presented in Table A. 27. 

140 Investment cost is based on a unit cost for on-shore terminals of 250 USD/tpa, source: Oxford Institute for Energy 
Studies, “The Outlook for Floating Storage and Regasification Units”, 2017 

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Table A. 27: Values applied to calculate LNG terminal charge in Ukraine 

Item 

Annual send-out capacity (bcm/yr) 
FSRU vessel cost (EUR) 
Facilities costs (EUR) 
Life cycle of FSRU (years) 
Expected rate of return on investment / discount 
rate 
Fixed operating expenses 
Vessel LNG consumption (1000m3/d) 
Assumed LNG opportunity cost (EUR/1000 m3) 
Variable operating expenses 
Terminal utilization factor 
LNG terminal charge (EUR/1000 m3) 

Value 
5 
260,000,000141 
190,000,000142 
30 (depreciation rate 3%) 

10% 

2.5% of CAPEX140 
16 
220 
1.1% of send-out 
50% 
25.9 

30% 
41.6 

70% 
19.2 

A2.2.7. Results of analysis 
Georgia 

The results of the netback analysis for Georgia, concerning the maximum supply price of LNG at 
the Georgian terminal, for each scenario of the assumed utilization, are presented in Table A. 28. 

Table A. 28: Calculated maximum competitive LNG price at the source per utilization rate, for current 
import price in Georgia 

Item 

Wholesale gas price in Georgia (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
206.0 
N/A 

70% 

-80.5 

119.4 

-6.1 

-48.3 

151.6 

-34.5 

165.4 

Table A. 29: Calculated maximum competitive LNG price at the source per utilization rate, for 25% 
import price increase in Georgia 

Item 

Wholesale gas price in Georgia (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
256 
N/A 

70% 

-80.5 

169.4 

-6.1 

-48.3 

201.6 

-34.5 

215.4 

141  Average cost of FSRU vessels, source: Oxford Institute for Energy Studies, “The Outlook for Floating Storage and 
Regasification Units”, 2017 
142 Estimate, based on benchmark jetty/piping costs and estimated connection to the Ukrainian transmission system 

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Table A. 30: Calculated maximum competitive LNG price at the source per utilization rate, for 50% 
import price increase in Georgia 

Item 

Wholesale gas price in Georgia (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

Ukraine 

30% 

Utilization of LNG terminal 
50% 
306 
N/A 

70% 

-80.5 

219.4 

-6.1 

-48.3 

251.6 

-34.5 

265.4 

The results of the netback analysis for Ukraine, concerning the maximum supply price of LNG at 
the  Ukrainian  terminal,  for  each  scenario  of  the  assumed  utilization,  covering  the  3  wholesale 
price scenarios (average, minimum, maximum) are presented in Table A. 31, Table A. 32 and 
Table A. 33 respectively.  

Table  A.  31:  Calculated  maximum  competitive  LNG  price  at  the  source  per  utilization  rate,  for 
average import price in Ukraine 

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
241 
N/A 

70% 

-41.6 

193.7 

-5.71 

-25.9 

209.4 

-19.2 

216.1 

Table  A.  32:  Calculated  maximum  competitive  LNG  price  at  the  source  per  utilization  rate,  for 
minimum import price in Ukraine  

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
198 
N/A 

70% 

-41.6 

150.7 

-5.71 

-25.9 

166.4 

-19.2 

173.1 

Table A. 33: Calculated maximum competitive LNG price at the source per utilization rate, for winter 
average import price in Ukraine 

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
257 
N/A 

70% 

-5.71 

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Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-41.6 

209.7 

-25.9 

225.4 

-19.2 

232.1 

Moldova 

The results of the netback analysis for Moldova, concerning the maximum supply price of LNG at 
the Ukrainian terminal, for each scenario of the assumed utilization, are presented in Table A. 34.  

Table A. 34: Calculated maximum competitive LNG price at the source per receiving terminal, for 
Moldova 

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Aggregate cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of LNG terminal 
50% 
151.4 
-17.0 

70% 

-41.6 

87.4 

-5.71 

-25.9 

103 

-19.2 

109.8 

A2.3. Netback analysis in case of LNG supplied from liquefaction 
terminal in Black Sea 
A2.3.1. Analysis approach 
Figure A. 44 outlines the netback analysis for deriving the competitive LNG price, in the case of 
regasified LNG, sourced from a liquefaction terminal located in Georgia.  

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Figure A. 44: Netback analysis to estimate competitive LNG price at the source, for LNG liquefied 
in the Black Sea 

The  initial  Steps  of  the  process  (Steps  1  to  4)  are  the  same  as  in  Sections  A2.1  and  A2.2. 
Additional costs considered are the LNG transportation costs (Step 5), charges for the liquefaction 
service (Step 6), and the tariff at the interconnection between the transmission system and the 
liquefaction terminal (Step 7). 

The resulting natural gas price from the netback analysis is the price that needs to be compared 
to  the  gas  price  in  Georgia,  to  ascertain  whether  LNG  is  competitive  to  prices  of  existing  gas 
sources in the Eastern Partner country.   

A2.3.2. Application in Eastern Partner countries 
Potential target Eastern Partner countries for a liquefaction terminal in Georgia are Ukraine and 
Moldova, provided that a receiving terminal in Ukraine is also developed. 

It is noted that when examining the in-country terminal in Ukraine, Step 2 is omitted. 

Based on this context, the calculations for the netback analysis steps are described in the sections 
below. 

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A2.3.3. Steps 1 to 4 
The calculations for Steps 1 to 4 are the same with those defined in Sections A2.2.3 – A.2.2.6. 

A2.3.4. Step 5: Definition of LNG transportation costs 
Transportation  from  the  liquefaction  plant  in  Georgia  to  the  receiving  terminal  in  Ukraine  is 
required. It is assumed that an LNG vessel with capacity of 74,000 m3 will be hired to transport 
LNG  to  the  target  destinations  (Romania,  Hungary,  Ukraine,  Moldova).  The  annual  cost  is 
calculated on the basis of the cost for hiring the vessel and its fuel consumption (Figure A. 45).  

Figure A. 45: Calculation of LNG transportation costs 

The assumptions and benchmarks applied in the calculation are presented in Table A. 35. 

Table A. 35: Values applied to calculate LNG transportation cost 

Item 

Cost for hiring LNG vessel (EUR/d) 
Transported volumes (m3 LNG/yr) 
Roundtrips required 
Days per round trip 
Fuel consumption (MT HFO/d) 
Fuel cost (EUR/MT) 
Transportation cost (EUR/1000 m3) 

Value 
50,000 
3,000,000 (90% utilization of liquefaction facility) 
50 
3 
50 
320 
5.5 

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A2.3.5. Step 6: Calculation of liquefaction cost 
The  cost  for  producing  LNG  at  the  liquefaction  plant  is  calculated  as  the  present  value  of  the 
required annual revenues (including recovery of all the investment costs and operating expenses 
and a return on the assets) per volume of produced LNG, for the full duration of the liquefaction 
plant’s life cycle. The approach applied to calculate the cost of gas liquefaction is presented in 
Figure A. 46. 

Figure A. 46: Calculation of gas liquefaction costs 

The liquefaction terminal is assumed to have an output capacity of 2 bcm/yr, and a utilization rate 
of 90% (with potential gas supply to Eastern Partners and EU countries). The assumptions and 
benchmarks  applied  in  the  calculation  are  presented  in  Table  A.  36.  The  investment  cost 
estimated for the 2 bcm/yr configuration of the AGRI Pipeline is applied as a basis. However, as 
the costs associated with the development of the facility are a key cost element in the analysis, 
and these may have changed, due to the introduction of new technologies (e.g. FLNG terminal), 
sensitivity analysis was performed, assessing also 80% and 60% of the investment costs. 

Table A. 36: Values applied to calculate gas liquefaction cost 

Item 

Cost of liquefaction terminal 

LNG production capacity 
Liquefaction plant investment cost (EUR) 
Life cycle of plant (years) 
Expected  rate  of  return  on  investment  / 
discount rate 

100% 

1,200,000,000143 

80% 
2 bcm/yr 
960,000,000 

60% 

720,000,000 

30 (depreciation rate 3%) 

10% 

143 Assumed equal to the investment cost of the 2 bcm/yr configuration of the AGRI Pipeline, source: GNERC, “Case 
Study: Georgia’s Growing Gas Market”, 2018 

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Fixed operating expenses 
Fuel gas (feed gas) consumption 
Assumed 
opportunity 
LNG 
(EUR/1000 m3) 
Utilization rate 
Liquefaction cost (EUR/1000 m3) 

cost 

2.5% of CAPEX144 
10% of gas input144 

220 

90% 

93.5 

109.6 

79.8 

A2.3.6. Step 7: Definition of exit charges to liquefaction terminal 
The exit tariff from the Georgian transmission system to the liquefaction terminal is assumed to 
be equal to the existing transmission tariff, 6.1 EUR/1000 m3.  

A2.3.7. Results of analysis 
Ukraine 

The results of the netback analysis for Ukraine, concerning the maximum supply price of natural 
gas in Georgia, for each scenario of the assumed Ukrainian receiving terminal utilization, covering 
the 3 wholesale price scenarios (average, minimum, winter average) are presented in Table A. 
37, Table A. 38 and Table A. 39 respectively. Furthermore, sensitivity analysis was performed on 
the liquefaction terminal investment costs, for Ukrainian winter average price and utilization 70% 
at the Ukrainian LNG receiving terminal (Table A. 40). 

Table A. 37: Calculated maximum competitive price of gas liquefied in Georgia, for average import 
price in Ukraine 

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of Ukrainian LNG terminal 
50% 
241.0 
N/A 

70% 

-41.6 

74.9 

-5.71 

-25.9 
-5.5 
-109.6 
-6.1 

90.6 

-19.2 

97.3 

Table A. 38: Calculated maximum competitive price of gas liquefied in Georgia, for minimum import 
price in Ukraine  

Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 

30% 

Utilization of Ukrainian LNG terminal 
50% 
198.0 
N/A 

70% 

-41.6 

-5.71 

-25.9 

-19.2 

144 Source: Oxford Institute for Energy Studies, “LNG Plant Cost Reduction”, 2018 

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LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-5.5 
-109.6 
-6.1 

47.6 

54.3 

31.9 

Table A. 39: Calculated maximum competitive price of gas liquefied in Georgia, for winter average 
import price in Ukraine 

 Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of Ukrainian LNG terminal 
50% 
257.0 
N/A 

70% 

-41.6 

90.9 

-5.71 

-25.9 
-5.5 
-109.6 
-6.1 

106.6 

-19.2 

113.3 

Table  A.  40:  Sensitivity  analysis  on  maximum  competitive  price  of  gas  liquefied  in  Georgia,  for 
winter average import price in Ukraine and 70% utilization of Ukrainian terminal 

 Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

100% 

Cost of liquefaction terminal 
80% 
256 
N/A 

60% 

-5.71 

-19.2 
-5.5 
-93.5 
-6.1 

127.0 

-109.6 

113.3 

-79.8 

140.7 

Moldova 

The results of the netback analysis for Moldova, concerning the maximum supply price of natural 
gas  in  Georgia,  for  each  scenario  of  the  assumed  Ukrainian  receiving  terminal  utilization,  are 
presented in Table A. 41. The results of a sensitivity analysis on the liquefaction terminal costs, 
for utilization rate of the Ukrainian terminal of 70% is presented in Table A. 42. 

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Table A. 41: Calculated maximum competitive price of gas liquefied in Georgia, for Moldova 

Item 

Wholesale gas price in Moldova (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

30% 

Utilization of Ukrainian LNG terminal 
50% 
151.5 
-17.0 

70% 

-41.6 

-31.4 

-5.71 

-25.9 
-5.5 
-109.6 
-6.1 

-15.7 

-19.2 

-9.0 

Table  A.  42:  Sensitivity  analysis  on  maximum  competitive  price  of  gas  liquefied  in  Georgia,  for 
Moldova and 70% utilization of Ukrainian terminal 

 Item 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Cross-border charges (EUR/1000 m3) 
Entry charges from LNG terminal to transmission 
(EUR/1000 m3) 
Charges at LNG terminal (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
Exit from Georgian system 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

100% 

Cost of liquefaction terminal 
80% 
151.5 
-17.0 

60% 

-5.71 

-19.2 
-5.5 
-93.5 
-6.1 

4.7 

-109.6 

-9.0 

-79.8 

18.4 

A2.4. Netback  analysis  in  case  of  LNG  supplied  via  trucks  to  a 
regasification terminal connected to the transmission 
A2.4.1. Analysis approach 
Figure A. 47 outlines the netback analysis for deriving the competitive LNG price, in the case of 
LNG transported from a neighbouring EU terminal to an LNG receiving terminal connected to the 
to the transmission system of the examined Eastern Partner country.  

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Figure A. 47: Netback analysis to estimate competitive LNG price at the source (LNG Terminal), for 
LNG delivered to a regasification terminal connected to the Eastern Partner country’s transmission 

The  starting  point  (Step  1)  for  the  analysis  is  the  wholesale  gas  price  in  the  Eastern  Partner 
country in question. From this price, all costs to arrive at the competitive price of LNG at the LNG 
terminal are sequentially estimated and subtracted: costs for entry in the transmission system of 
the Eastern Partner country (Step 2), infrastructure cost for an LNG receiving facility (unloading, 
storage and regasification) connected to the transmission system (Step 3), transportation costs 
of LNG by the LNG trucks to the receiving facility (Step 4), and the cost of loading LNG to trucks 
at the LNG terminal (Steps 5). 

A2.4.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
supply  of  LNG  from  neighbouring  LNG  terminals  to  a  regasification  facility  connected  to  the 
country’s transmission system is an applicable option for Ukraine.  

The development of a regasification facility in the western part of Ukraine is assumed to be close 
to  the  LNG  terminals  in  Świnoujście  and  Klaipeda.  Other  neighbouring  terminals  are  not 
considered, due to their distance to Ukraine. 

For the purpose of the analysis, we assume that the regasification will cover annual demand of 
500  mcm,  that  is  close  to  the  maximum  nominal  capacity  of  the  Klaipeda  reloading  station 
(100 m3 LNG/h). The assumed demand corresponds to around 1.4 mcm/d, i.e. 2,300 m3 LNG/d.   

Based on this context, the calculations for the netback analysis steps are described in the sections 
below. 

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A2.4.3. Step  1:  Definition  of  wholesale  gas  prices  in  Eastern  Partner 
countries 
The import gas prices (average, minimum, winter average) defined for Ukraine in Section A2.1.3, 
for the case of supplies from the EU terminals, are applied.  

A2.4.4. Step 2: Definition of entry charges from regasification facility 
An  estimate  for  the  tariff  of  the  entry  point  connecting  the  LNG  regasification  facility  to  the 
transmission systems is made, based on the existing tariffs applied by Ukrtransgaz. We assume 
an entry tariff of 3.3 EUR/1000 m3, equal to the tariff for gas storage withdrawal145.  

A2.4.5. Step 3: Calculation of receiving facility service fee 
The service charge for the use of the LNG receiving facility (unloading, storage, regasification) is 
calculated  as  the  present  value  of  the  required  annual  revenues  (including  recovery  of  all  the 
facility’s  investment  costs  and  operating  expenses  and  a  return  on  the  assets)  per  volume  of 
regasified gas, for the full duration of the facility’s life cycle. The approach applied to calculate the 
service charge for the LNG receiving facility is presented in Figure A. 48.  

Figure A. 48: Calculation of service charge for receiving facility 

The  average  daily  assumed  send-out  gas  needs  are  1.4  mcm/d  (2,300  m3  LNG/d).  With  a 
minimum  stock  requirement  of  7  days,  a  storage  of  16,100  m3  should  be  installed.  As  a 
regasification  facility  of  a  significant  size  is  required,  to  accommodate  high  pressure  pumps 

145 Source: Ukrtransgaz Price List 

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allowing  injection  in  the  transmission  system,  large  boil-off  gas  handling  system  and  pipings, 
multiple truck unloading bays, etc, benchmark unit costs of on-shore receiving terminals, adjusted 
for this particular case should be used. The benchmarks and assumptions used in the calculations 
of the service charge for the receiving facility are presented in Table A. 43.  

Table A. 43: Values applied to calculate service charge for receiving facility 

Receiving facility investment costs (EUR) 
Payback period (years) 

Item 

Expected rate of return on investment / discount rate 

Operating expenses 
Regasification service charge (EUR/1000 m3) 

Value 
45,000,000146 
20 (depreciation rate 5%) 
10% (assuming that the infrastructure will be 
regulated) 
5% of investment costs147 
14.6 

A2.4.6. Step 4: Calculation of transportation cost for LNG truck 
The  cost  for  transporting  the  LNG  volumes  via  truck  from  the  receiving  LNG  terminal  to  the 
regasification facility is calculated as the present value of the required annual revenues (including 
recovery of all the LNG truck(s) investment costs and operating expenses and a return on the 
assets)  per  volume  of  transported  LNG,  for  the  full  duration  of  the  LNG  truck’s  life  cycle.  The 
approach applied to calculate the transportation cost is presented in Figure A. 49. 

146 Estimation assuming unit installation cost of 150 USD/tpa, considering that unit cost of coastal terminal is around 
175 USD/tpa, source: Oxford Institute for Energy Studies, “The Outlook for Floating Storage and Regasification Units”, 
2017 
147 Assumption based on regasification terminals 

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Figure A. 49: Calculation of transportation cost for LNG trucks 

Based on the assumed send-out volumes of the regasification facility, on a daily basis at least 
2,300 m3 of LNG have to be transported and stored. This would require a minimum of 46 LNG 
trucks with 50 m3 LNG capacity each operating on a year-round basis. To allow for contingencies, 
a fleet of 55 trucks is assumed. The distances considered are for a facility located in the western 
part  of  Ukraine.  The  assumptions  and  benchmarks  applied  in the  calculation  are  presented  in 
Table A. 44. 

Table A. 44: Values applied to calculate LNG transportation cost 

Item 

Number of trucks 
Cost per truck (EUR) 
Life cycle of truck (years) 
Expected rate of return on investment / discount rate 
Variable cost (EUR/km) 
LNG truck capacity (m3(LNG)) 
Distance per round trip (km) 
Annual volumes of LNG transported (thousand m3 LNG) 
LNG transportation cost (EUR/1000 m3) 

Values per terminal 

Świnoujście 

Klaipeda 

55 
310,000148  
8 (depreciation rate 13%)148 
20% 
1.45148 
50148 

2,000 

103.4 

833 

1,800 

93.7 

148 Source: Interview with Klaipedos Nafta 

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A2.4.7. Step  5:  Definition  of  LNG  truck  loading  cost  at  neighbouring 
terminals 
The price charged by the LNG terminals neighbouring to Eastern Partners (Świnoujście, Klaipeda 
reloading station) for LNG truck loading service is as follows149: 

 

 

In Świnoujście, the fee for truck loading service amounts to 10.4 EUR/1000m3  150; 

In Klaipeda, the fee for truck loading service amounts to 24 EUR/1000 m 3. In this case, 
an additional fee is required for delivering LNG to the reloading station, from the FSRU 
or another source. Such a fee depends on the distance, availability of the vessels for 
certain delivery windows, and may range from around 24 – 70 EUR/1000 m3  148. For 
the purpose of this analysis we assume the minimum  transportation cost to the LNG 
reloading  station  (24  EUR/m3),  and  therefore  the  aggregate  cost  for  truck  loading  in 
Klaipeda is 48 EUR/1000 m3.  

A2.4.8. Results of analysis 
The results of the netback analysis for Ukraine, concerning the maximum LNG supply price at the 
neighbouring terminals, covering the 3 wholesale price scenarios (average, minimum, maximum) 
are presented in Table A. 45 Table A. 46 and Table A. 47 respectively.  

Table A. 45: Calculated maximum competitive price of LNG supply to gas transmission customers, 
for average import price in Ukraine  

Item 

Values per terminal 

Świnoujście 

Klaipeda 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Entry charges from regasification to transmission 
(EUR/1000 m3) 
Regasification cost (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Truck loading cost (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

241 

-3.3 

-14.6 

103.4 
-10.4 

109.3 

-93.7 
-48.0 

81.4 

Table A. 46: Calculated maximum competitive price of LNG supply to gas transmission customers, 
for minimum import price in Ukraine  

Item 

Values per terminal 

Świnoujście 

Klaipeda 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Entry charges from regasification to transmission 
(EUR/1000 m3) 
Regasification cost (EUR/1000 m3) 

198 

-3.3 

-14.6 

149 Prices in EUR/MWh have been converted to EUR/lt(LNG) using the GCV assumptions presented in Annex 7 
150 Source: Polskie LNG, “LNG Regasification Services Tariff”, December 2018 

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LNG transportation cost (EUR/1000 m3) 
Truck loading cost (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

-10.4 

66.3 

-93.7 
-48.0 

38.4 

Table A. 47: Calculated maximum competitive price of LNG supply to gas transmission customers, 
for winter average import price in Ukraine 

Item 

Values per terminal 

Świnoujście 

Klaipeda 

Wholesale gas price in Ukraine (EUR/1000 m3) 
Entry charges from regasification to transmission 
(EUR/1000 m3) 
Regasification cost (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Truck loading cost (EUR/1000 m3) 
Maximum LNG price at the terminal 
(EUR/1000 m3) 

257 

-3.3 

-14.6 

-10.4 

125.3 

-93.7 
-48.0 

97.4 

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Annex 3: Netback Analysis – Gas-to-Other Fuels 
Competition 

A3.1. Netback analysis for LNG as fuel for long-haul trucks  
A3.1.1. Analysis approach 
Figure A. 50 outlines the process of netback analysis for deriving the competitive LNG price in an 
Eastern Partner country for LNG to be used as fuel by trucks (converting long haul trucks currently 
running on diesel fuel to run on LNG).  

Figure A. 50: Netback analysis to estimate competitive LNG price at the source, for LNG as fuel for 
long-haul trucks, in competition with diesel 

The starting point (Step 1) for the analysis is the equivalent LNG price to the price/cost paid by 
trucks, for diesel, in the Eastern Partner country examined. It is noted that the equivalent LNG 
price takes into account the efficiency of LNG as a fuel versus diesel. From this equivalent LNG 
price, all costs to arrive at the competitive price of LNG at the source are sequentially estimated 
and  subtracted:  costs  of  retrofitting  truck  engines  (Step  2),  infrastructure  costs  for  LNG  filling 
stations (Step 3), the transportation costs of LNG by the LNG trucks to the filling stations (Step 
4), and the cost of loading LNG to trucks at the source or the costs of liquefaction of gas from the 
pipeline in the case of a mini liquefaction facility (Steps 5 – 6). 

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There are three potential variants for the LNG deliveries (LNG supply variants) from the source 
to the filling stations, each variant having different costs to be incurred under Steps 5 and 6:   

a.  (Steps 5a and 6a): The LNG trucks load and transport LNG from a terminal outside the 

Eastern Partner country.  

b.  (Steps 5b and 6b): The LNG trucks load and transport LNG from a terminal in the Eastern 
Partner  country  (regasification  or  liquefaction  terminal),  provided  it  is  feasible  for  the 
country to have its own terminal. 

c.  (Steps 5c and 6c): A mini liquefaction facility is installed to convert pipeline gas to LNG, 

which is then loaded into LNG trucks for delivery to end-customers.  

The resulting LNG price from the netback analysis is the price that needs to be compared to the 
regional price for spot LNG deliveries (in case LNG is sourced from a terminal) and/or the price 
of  piped  natural gas (in case  LNG  is  produced using  a  liquefaction facility),  so as to  ascertain 
whether LNG is competitive to prices of diesel for the Eastern Partner country concerned.   

It is noted that the diesel prices used in the analysis exclude VAT, but are inclusive excise taxes 
or  any  other  taxes  applied  for  the  fuel.  On  the  other  hand,  it  is  assumed  that  LNG  used  for 
transport will be exclusive of any taxes. Inclusion of taxes on the LNG price would decrease its 
competitiveness vis-à-vis diesel.   

In  case  the  information  available  for  a  country’s  long-haul  trucks  (number  of  local  and  transit 
trucks, destinations and distances covered) is not sufficiently detailed, it is not possible to make 
reasonable assumptions to estimate the market size for use of LNG in road transport. In these 
cases, instead of estimating the maximum LNG price for the option to be competitive, following 
sequentially the steps 1 – 6 of Figure A. 50, we assess the minimum LNG market size required in 
steps 3, 4 and 5 to achieve a competitive LNG / natural gas price at the beginning of the supply 
chain. 

A3.1.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
use of LNG as fuel for long-haul trucks is an applicable option for Armenia, Azerbaijan, Belarus, 
Georgia and Ukraine. The LNG supply variants that are relevant to each Eastern Partner country 
differ (Table A. 48): 

  LNG terminal outside the country: Relevant to Belarus and Ukraine for LNG  supplied 
from the Świnoujście LNG terminal and Klaipeda FSRU and LNG reloading station151, 
and to Armenia for LNG from a potential LNG terminal in Georgia. 

  Eastern Partner LNG terminal: Relevant on to a receiving terminal  with truck loading 
facilities developed in Georgia or Ukraine, which have direct access to the Black Sea, 
as well as a liquefaction terminal in Georgia, that could also be used to supply LNG to 
the region. 

151 For the Gas-to-Other fuels competition analysis, the LNG supply from the Klaipeda FSRU is examined together with 
the Klaipeda LNG reloading station. 

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  Mini  liquefaction  facility:  Relevant  to  all  Eastern  Partner  countries,  as  the  mini 
liquefaction facility will be directly connected to each country’s transmission system. 

Table A. 48: LNG supply variants for LNG-fueled trucks per Eastern Partner country 

LNG Terminal outside country 
In-country LNG (receiving or 
liquefaction) terminal 
Mini liquefaction facility 

Armenia 
 

Azerbaijan 

Belarus 
 

Georgia 

 

 

 

 
 

Ukraine 
 
 
 

Based on this context, the calculations for each of the netback analysis steps are described in the 
sections below. 

A3.1.3. Step 1: Calculation of LNG equivalent price 
The  approach  applied  to  calculate the  LNG  price  equivalent  to the  diesel  price  at the  pump  is 
presented in Figure A. 51 below. 

Figure A. 51: Calculation of LNG equivalent price 

To provide contextualized estimates for each Eastern Partner country, we have applied current 
diesel prices per country. Table A. 49 below presents the values used to calculate the equivalent 
LNG price for each examined Eastern Partner country.  

Table A. 49: Values applied to calculate LNG equivalent price 

Item 
Diesel price (EUR/lt) 
Diesel consumption (lt/km) 
LNG consumption (lt/km) 

Armenia  Azerbaijan  Belarus 
0.59154 
0.26153 
0.64152 
0.326157 
0.495158 

Georgia 
0.71155 

Ukraine 
0.76156 

152 Source: Maxoil website (accessed 1/11/2019) 
153 Source: Azpetrol website (accessed 1/11/2019) 
154 Source: Belarus Ministry of Energy 
155 Source: SOCAR Georgia website (accessed 1/11/2019)  
156 Source: https://index.minfin.com.ua/ua/markets/fuel/dt/ (accessed 1/11/2019) 
157 Source: International Council on Clean Transportation, “Fuel consumption testing of tractor trailers in the European 
Union and the United States”, 2017 
158 Source: Volvo, “Volvo introduces new LNG truck”, October 2017 

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Item 

Armenia  Azerbaijan  Belarus 

Georgia 

Ukraine 

Equivalent LNG price EUR/m3 
(LNG) 
Equivalent LNG price EUR/1000 m3 
(gas) 

421.5 

171.2 

388.6 

467.6 

500.5 

702.5 

285.4 

647.6 

779.3 

834.2 

A3.1.4. Step 2: Calculation of costs for fuel switching 
Fuel switching from diesel to LNG would require retrofitting of the truck engine, while the LNG 
price at the pump would have to be discounted compared to that of diesel, so that the truck owner 
can be incentivised to switch fuels.  

The  approach applied to  calculate  the  costs  (including  incentives), for  switching from  diesel to 
LNG, is presented in Figure A. 52 below. 

Figure A. 52: Calculation of costs for fuel switching 

The calculations require a number of assumptions concerning the desired incentives of the truck 
owner (payback period of truck retrofitting costs, discounts on LNG price), as well as the use of 
the  truck  (number  of  round-trips  per  annum,  distance  of  each  round-trip).  The  applied 
assumptions  and  benchmarks  are  presented  in  Table  A.  50.  As  there  are  no  country-specific 
elements in the calculations the same values apply for all examined Eastern Partner countries. 

Table A. 50: Values applied to calculate LNG switching costs 

Item 

Armenia 

Retrofitting costs (EUR) 
Payback period requirement (years) 

Azerbaijan 

Georgia 

Value per country 
Belarus 
22,000159 
5 

159 Assumption based on reported range of prices from various sources 

Ukraine 

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2,000160 

25% 
91 (corresponding to 1 trip per 4 days) 
1,000 (corresponding to 1 LNG tank filling) 
0.495 
296.00 

Additional maintenance cost for LNG 
(EUR/yr) 
Uplift for truck-owner incentive (%) 
Number of annual round-trips 
Distance per round-trip (km) 
LNG consumption (lt/km) 
LNG switching costs EUR/1000 m3 
A3.1.5. Step 3: Calculation of service charge for LNG filling station 
The service charge for the use of the LNG filling station is calculated as the present value of the 
required annual revenues (including recovery of all the station’s investment costs and operating 
expenses and a return on the assets) per volume of supplied LNG, for the full duration of the filling 
station’s life cycle. The approach applied to calculate the service charge for the LNG filling station 
is presented in Figure A. 53. 

Figure A. 53: Calculation of service charge for filling station 

Due  to  the  lack  of  transport  data  of  sufficient  detail  to  make  reasonable  assumptions  on  the 
potential number of LNG-fired trucks in each Eastern Partner country, the minimum number of 
trucks for this LNG option to be viable are estimated as part of this netback analysis. 

The assumptions and benchmarks applied in the calculation are presented in Table A. 51. It is 
noted  that  these  calculations  are  based  on  the  development  of  a  new  LNG  filling  station.  The 
potential upgrade of an existing fuel  station or development of an L-CNG station could lead to 
reduced  costs,  due  to  reduction  in  operating  expenses  and  economies  of  scale  in  investment 
costs. 

160 Source: I. Smajla et al. (Energies Journal),” Fuel Switch to LNG in Heavy Truck Traffic”, 2019 

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Table A. 51: Values applied to calculate service charge for LNG filling station 

Item 

Filling station investment costs (EUR) 

Filling station operating expenses 
(EUR) 
Life cycle of filling station (years) 
Expected rate of return on investment 
/ discount rate 
Days between truck refueling 
Truck LNG tank size (lt(LNG)) 
Number of LNG-fired trucks 

Azerbaijan 

Value per country 
Armenia 
Ukraine 
Belarus 
555,000 (including cost for filling station development 528,000 
EUR161, for filling station with 4 truck slots, and assuming cost 
of land of 27,000 EUR) 
119,500161 (including staff costs for 24/7 operation of the 
station) 
10 (depreciation rate 10%)161 

Georgia 

20% 

4 
495158 
Minimum number to be calculated through netback analysis 

A3.1.6. Step 4: Calculation of transportation cost for LNG truck 
The approach applied to calculate the cost for transporting LNG from its source (LNG terminal or 
liquefaction facility) to the receiving facility is the same with the one presented in Figure A. 49, in 
Section A2.4.6. 

The  annual  volumes  of  LNG  transported  are  equal  to  the  gas  volumes  supplied  at  the  filling 
station, defined in Step 3, and thus dependent on the number of LNG-fired trucks (the minimum 
number of which will is estimated as part of the netback analysis).   

The distance travelled by the LNG truck depends on the LNG variant examined. For the case of 
LNG terminals outside the examined Eastern Partner country, separate calculations are carried 
out  for  each  relevant  terminal.  For  the  case  of  developing  a  liquefaction  facility  in  the  Eastern 
Partner country, the facility is assumed to be close to the filling station.  

The assumptions and benchmarks applied in the calculation are presented in Table A. 52. 

Table A. 52: Values applied to calculate LNG transportation cost 

Item 

Truck cost (EUR) 

Life cycle of truck (years) 
Expected rate of return on investment 
/ discount rate 
Variable cost (EUR/km) 
LNG truck capacity (m3(LNG)) 
Distance per round trip (from 
Świnoujście LNG terminal) 
Distance per round trip (from 
Klaipeda LNG terminal) (km) 

Armenia 

Azerbaijan 

Value per country 
Ukraine 
Belarus 
310,000148 (cost for one truck – cost for additional trucks is 
estimated in case more LNG transportation capacity is 
required) 
8 (depreciation rate 13%)148 

Georgia 

20% 

1.45148 
50148 

2,400 

1,000 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

2,800 

2,000 

161 Source: NGVA Europe, EC 7th Framework Programme, “Cost analysis of LNG refuelling stations”, 2016 

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Distance per round trip (from Ukraine 
LNG terminal) (km) 
Distance per round trip (from Georgia 
LNG terminal) (km) 
Distance per round trip (from in-
country liquefaction facility) (km) 
Annual volumes of LNG transported 

N/A 

1,100 

20 

N/A 

N/A 

20 

N/A 

N/A 

20 

N/A 

600 

20 

1,200 

N/A 

20 

Depends on the number of LNG-fired trucks (defined in step 3) 

A3.1.7. Steps 5a-6a: Calculation of LNG truck loading cost at neighboring 
terminals 
The truck loading costs for Świnoujście and Klaipeda LNG terminals are applied (Table A. 53), as 
described in Section A2.4.7. 

Table A. 53: Values used for LNG truck loading 

Terminal 

Świnoujście LNG terminal 

Klaipeda LNG terminal 

Truck loading cost (EUR/1000m3) 
10.4 
48 (including transportation from terminal to 
reloading station and truck loading) 

A3.1.8. Steps 5b-6b: Calculation of LNG truck loading cost at terminals in 
Eastern Partner countries 
In this analysis we assume that the potential LNG receiving terminals in Ukraine and Georgia will 
be FSRUs, in which case on-shore LNG reloading stations will be required. The LNG truck loading 
costs are assumed to be similar to those defined in Step 5a for Klaipeda, i.e. 48 EUR/1000 m3. 

In case of development of an on-shore liquefaction terminal in Georgia, the LNG truck loading 
costs are assumed to be similar to those defined in Step 5a for Świnoujście (10.4 EUR/ 1000 m3). 
In  this  case,  a  charge  for  liquefaction  service  must  also  be  included  in  the  calculations 
(corresponding to the liquefaction terminal tariff calculated in Section A2.3.5). 

Table A. 54 summarizes the values used for LNG truck loading costs at each examined terminal 
(Steps 5a and 5b). 

Table A. 54: Values used for LNG truck loading 

Terminal 

Świnoujście LNG terminal 

Klaipeda LNG terminal 

Ukraine LNG terminal 
Georgia LNG receiving terminal 

Georgia liquefaction terminal 

Truck loading cost (EUR/1000m3) 
10.4 
48 (including transportation from terminal to 
reloading station and truck loading) 
48 (as in Klaipeda) 
48 (as in Klaipeda) 
117.8 (includes liquefaction tariff, and truck 
loading as in Świnoujście) 

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A3.1.9. Steps 5c-6c: Calculation of  liquefaction cost at mini liquefaction 
facility 
The  cost  for  producing  LNG  at  a  liquefaction  facility  is  calculated  as  the  present  value  of  the 
required annual revenues (including recovery of all the investment costs and operating expenses 
and a return on the assets) per volume of produced LNG, for the full duration of the liquefaction 
facility’s life cycle. The approach applied to calculate the cost of gas liquefaction is presented in 
Figure A. 54. 

Figure A. 54: Calculation of gas liquefaction costs 

The annual volumes of LNG produced are equal to the gas volumes supplied at the filling station, 
defined in Step 3, and thus dependent on the number of LNG-fired trucks (the minimum number 
of  which  is  estimated  as  part  of  the  netback  analysis).  Furthermore,  the  capacity  of  the  mini 
liquefaction facility (and therefore its investment requirements) depends on the estimated size of 
the market. It is noted that a benchmark average investment cost for liquefaction facilities162 is 
applied  in  the  calculations,  not  taking  into  consideration  a  specific  liquefaction  process.  The 
assumptions and benchmarks applied in the calculation are presented in Table A. 55. 

Table A. 55: Values applied to calculate gas liquefaction cost 

Item 

Liquefaction  facility  investment  cost 
(EUR) 
Life cycle of truck (years) 
Expected rate of return on investment 
/ discount rate 
Operating expenses 

Azerbaijan 

Value per country 
Belarus 
Armenia 
7,700,000 – 12,500,000 (for capacities ranging from 16 ton/d to 
50 ton/d of LNG production)162 
20 (depreciation rate 5%) 

Georgia 

Ukraine 

20% 

2% of investment costs163 

162 Source: World Bank, “Mini / Micro LNG for commercialization of small volumes of associated gas”, 2015 
163 Source: Lantau Group, “Pricing of LNG from Small Scale Facilities – Some Examples from Indonesia and Thailand”, 
2012 

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A3.1.10. Results of analysis 
The  available  information  on  the  Eastern  Partner  countries’  transport  sector  is  not  of  sufficient 
granularity  to  allow  identification  of  the  number  of  long-haul  trucks  operating  in  the  country 
(nationally  or  as  transit),  and  therefore  we  make  reasonable  assumptions  on  the  prospective 
penetration of LNG-fired trucks. For this reason, the analysis carried out estimated the minimum 
number of LNG-fired trucks that are required in the country, in order for this LNG option to be 
commercially attractive, under specific assumptions of LNG and natural gas supply prices. 

Five price scenarios at the beginning of the supply chain have been examined for each supply 
variant, covering the current LNG or natural gas price (depending on the variant) and sensitivity 
analysis for its potential increase (+25% and +50%) or decrease (-15% and -25%). The assumed 
LNG  prices  (Table A.  56)  depend  on the  LNG  terminal (same for  all  countries  supplied  by  the 
terminal), while natural gas prices for liquefaction (Table A. 57) are country specific, and include 
the wholesale price and transmission costs for transporting the gas up to the liquefaction facility.   

Table A. 56: LNG prices at LNG terminals examined  

Terminal 

Świnoujście LNG terminal164 
Klaipeda LNG terminal165 
Ukraine LNG terminal166 
Georgia LNG receiving terminal166 
Georgia liquefaction terminal167 

Assumed price at terminal (EUR/1000m3) 

Base price 
200 
200 
220 
220 
222 

+25% 
250 
250 
275 
275 
277 

+50% 
300 
300 
330 
330 
333 

-15% 
170 
170 
187 
187 
189 

-25% 
150 
150 
165 
165 
166 

Table A. 57: Natural gas prices for liquefaction examined 

Country 

Armenia168 
Azerbaijan169 
Belarus170 
Georgia171 
Ukraine172 

Assumed price at liquefaction facility (EUR/1000m3) 
-25% 
Base price 
137 
183 
64 
85 
175 
234 
166 
222 
190 
254 

+25% 
229 
107 
293 
277 
318 

+50% 
275 
128 
351 
333 
381 

-15% 
155 
72 
200 
189 
216 

164 As information is not available, the same price as Klaipeda is used 
165 Source: DG Energy, “Gas Market Report Q2 2019” 
166 The price for LNG in Black Sea (Ukraine and Georgia) is assumed to be the price at the Greek Revythoussa terminal 
(210  EUR/1000m3,  source:  DG  Energy,  “Gas  Market  Report  Q2  2019”),  with  an  uplift  of  5%  to  reflect  additional 
transportation cost and crossing through the Bosporus straits.  
167 Equal to the gas price in the Georgian market (Source: GEOSTAT) 
168 Source: PSRC, “Tariffs for natural gas supply to consumers” 
169 Source; Azerbaijan Tariff Council, “Natural gas processing, transportation, wholesale and retail tariffs”, 2019 
170 Source: Ministry of Energy 
171 Price  for  with demand  band 2.5  –  25  mcm/yr  ,  source:  GEOSTAT,  “Data  on  Consumer Prices  of  Electricity and 
Natural Gas, 2019” 
172 Average  wholesale  price  for  September  2018  –  September  2019  (Source:  Ukrainian  Energy  Exchange),  plus 
transportation tariff (Source: UTG) 

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The calculation results (minimum volumes of LNG and minimum number of LNG-fired trucks) per 
country and LNG supply variant, for the five price scenarios are presented in the Tables below. 
Only the supply variants relevant to each country are presented. It is noted that the cases in which 
the minimum LNG market size is calculated to be over 1,000 LNG-fuelled trucks are not presented 
in the Tables, as a high penetration of LNG in transport would be required in the relevant country 
compared to the EU experience (around 6,000 trucks across EU in 2019173).  

Armenia 

Table A. 58: Minimum number of LNG-fired trucks for Armenia  

LNG supply variant 

Georgia LNG receiving terminal 
Georgia liquefaction terminal 
Mini liquefaction facility in-country 

Minimum number of LNG-fired trucks  
Price scenario 

Base price 
134 
- 
339 

+25% 
454 
- 
505 

+50% 
- 
- 
786 

-15% 
97 
298 
290 

-25% 
82 
167 
271 

Table A. 59: Minimum LNG volumes supplied annually for Armenia  

LNG supply variant 

Georgia LNG receiving terminal 
Georgia liquefaction terminal 
Mini liquefaction facility in-country 

Azerbaijan 

Minimum number LNG volumes supplied (m3 LNG/yr)  
Price scenario 

Base price 
6,048 
- 
15,295 

+25% 
20,485 
- 
22,789 

+50% 
- 
- 
35,499 

-15% 
4,384 
13,482 
13,120 

-25% 
3,697 
7,534 
12,240 

The very low diesel price (0.26 EUR/lt) results in an equivalent LNG price (285.4 EUR/1000 m3) 
that is lower than the required switching costs (296 EUR/1000 m3). Consequently, introduction of 
LNG is not possible at a competitive price.  

Belarus 

Table A. 60: Minimum number of LNG-fired trucks for Belarus  

LNG supply variant 

Świnoujście LNG terminal 
Klaipeda LNG terminal 
Mini liquefaction facility in-country 

Minimum number of LNG-fired trucks  
Price scenario 

Base price 
- 
205 
- 

+25% 
- 
- 
- 

+50% 
- 
- 
- 

-15% 
210 
134 
604 

-25% 
155 
109 
480 

Table A. 61: Minimum LNG volumes supplied annually for Belarus  

LNG supply variant 

Świnoujście LNG terminal 
Klaipeda LNG terminal 
Mini liquefaction facility in-country 

Minimum number LNG volumes supplied (m3 LNG/yr)  
Price scenario 

Base price 
N/A 
9,281 
- 

+25% 
- 
- 
- 

+50% 
- 
- 
- 

-15% 
9,492 
6,050 
27,302 

-25% 
6,982 
4,925 
21,678 

173 Source: NGVA, “NGVA Europe marks the 200th European LNG fuelling station with a revamp of its stations map”, 
May 2019 

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Georgia 

Table A. 62: Minimum number of LNG-fired trucks for Georgia  

LNG supply variant 

Georgia LNG receiving terminal 
Georgia liquefaction terminal 
Mini liquefaction facility in-country 

Minimum number of LNG-fired trucks  
Price scenario 

Base price 
62 
101 
279 

+25% 
87 
195 
379 

+50% 
149 
N/A 
642 

-15% 
53 
79 
248 

-25% 
50 
68 
230 

Table A. 63: Minimum LNG volumes supplied annually for Georgia  

LNG supply variant 

Georgia LNG receiving terminal 
Georgia liquefaction terminal 
Mini liquefaction facility in-country 

Ukraine 

Minimum number LNG volumes supplied (m3 LNG/yr) 
Price scenario 

Base price 
2,791 
4,573 
12,624 

+25% 
3,948 
8,807 
17,098 

+50% 
6,749 
N/A 
28,978 

-15% 
2,375 
3,554 
11,204 

-25% 
2,255 
3,072 
10,389 

Table A. 64: Minimum number of LNG-fired trucks for Ukraine  

LNG supply variant 

Świnoujście LNG terminal 
Klaipeda LNG terminal 
Ukraine LNG terminal 
Mini liquefaction facility in-country 

Minimum number of LNG-fired trucks  
Price scenario 

Base price 
60 
60 
54 
256 

+25% 
82 
80 
73 
353 

+50% 
125 
123 
112 
583 

-15% 
52 
52 
47 
227 

-25% 
48 
47 
43 
210 

Table A. 65: Minimum LNG volumes supplied annually for Ukraine  

LNG supply variant 

Świnoujście LNG terminal 
Klaipeda LNG terminal 
Ukraine LNG terminal 
Mini liquefaction facility in-country 

Minimum number LNG volumes supplied (m3 LNG/yr) 
Price scenario 

Base price 
2,731 
2,691 
2,462 
11,584 

+25% 
3,710 
3,628 
3,315 
15,943 

+50% 
5,650 
5,536 
5,074 
26,324 

-15% 
2,370 
2,334 
2,128 
10,232 

-25% 
2,172 
2,141 
1,958 
9,465 

A3.2. Netback  analysis  for  LNG  supply  to  off-grid  distribution 
systems  
A3.2.1. Analysis approach 
Figure A. 55 outlines the process of netback analysis for deriving the competitive LNG price in an 
Eastern Partner country in the case LNG is used as a transportation modality of natural gas to an 
off-grid  distribution  system,  the  potential  retail  end-customers  of  which  are  currently  using 
alternative fuels (e.g. oil products or firewood).   

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Figure  A. 55: Netback analysis to estimate competitive LNG price at the source, for LNG used  to 
supply off-grid distribution systems 

The starting point (Step 1) for the analysis is the equivalent natural gas price to the price that end-
customers pay, in the Eastern Partner country examined, for the alternative fuel, for the specific 
use. It is noted that the equivalent gas price takes into account the efficiency of natural gas versus 
the competing fuel. From this equivalent gas price, all costs to arrive at the competitive price of 
LNG at the source are sequentially estimated and subtracted: costs of retrofitting equipment to 
burn  gas  (Step  2),  costs  for  development,  operation  and  maintenance  of  the  local  distribution 
system (Step 3), infrastructure cost for a small scale unloading, storage and regasification facility 
connected to the distribution system (Step 4), transportation costs of LNG by the LNG trucks to 
the regasification facility (Step 5), and the cost of loading LNG to trucks at the source or the costs 
of liquefaction of gas from the pipeline in the case of a mini liquefaction facility (Steps 6 – 7). 

As in the case of LNG as fuel for long-haul trucks, there are three potential LNG supply variants 
from the source to the regasification terminal, including: 

a.  (Steps 6a and 7a): The LNG trucks load and transport LNG from a terminal outside the 

Eastern Partner country.  

b.  (Steps 6b and 7b): The LNG trucks load and transport LNG from a terminal in the Eastern 
Partner  country  (regasification  or  liquefaction  terminal),  provided  it  is  feasible  for  the 
country to have its own terminal. 

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c.  (Steps 6c and 7c): A mini liquefaction facility is installed to convert pipeline gas to LNG, 

which is then loaded into LNG trucks for delivery to end-customers.  

The resulting LNG price from the netback analysis is the price that needs to be compared to the 
regional price for spot LNG deliveries (in case LNG is sourced from a terminal) and/or the price 
of piped natural gas (in case LNG is produced using a mini liquefaction facility), so as  to ascertain 
whether LNG is competitive to prices of competing fuels for off-grid retail end-customers in the 
Eastern Partner country concerned.  

It is noted that the prices of competing fuels used in the analysis exclude VAT, but are inclusive 
excise taxes or any other taxes applied. On the other hand, it is assumed that the sourced LNG 
used to supply the distribution system will be exclusive of any taxes. Inclusion of taxes on the 
LNG price would decrease its competitiveness vis-à-vis the competing fuel.  

A3.2.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
use  of  LNG  to  supply  off-grid  distribution  systems  is  an  applicable  option  for  Azerbaijan  and 
Georgia.  

For  Georgia,  the  LNG  supply  variants  applicable  are  the  development  of  an  LNG  receiving  or 
liquefaction terminal in the country, or the use of a mini liquefaction facility. 

For  Azerbaijan,  the  LNG  supply  variant  applicable  is  the  use  of  a  mini  liquefaction  facility 
connected to the Azeri transmission system. 

Calculations for the use of LNG to supply distribution system in ungasified towns in Georgia are 
provided  as  a  case  study,  using  inputs  provided  by  the  Ministry  of  Economy  and  Sustainable 
Development of Georgia. The examined towns, which have not yet been gasified as they are in 
mountainous  regions,  include  Chiatura,  Oni,  Aspindza,  Borjomi  and  Mestia.  The  analysis 
assumes that only households, currently using firewood (the dominant fuel in urban areas outside 
big cities in Georgia), will switch to gas. The netback analysis performed focuses on the unit costs 
for a single residential consumer in Chiatura. 

Based on this context, the calculations for each of the netback analysis steps are described in the 
sections below. 

A3.2.3. Step 1: Calculation of natural gas equivalent price 
The approach applied to calculate the natural gas price equivalent to that of firewood at the end-
consumer is presented in Figure A. 56 below. It is noted that the existing firewood consumption 
in  urban  areas  of  Georgia  (3.1  m3/yr  per  household174)  is  significantly  lower  than that  of  other 
countries  (e.g.  12  m3/yr  per  household  in  Italy175).  This  indicates  that  the  use  of  firewood  in 
Georgia is not a typical one, and consequently the heating volumes used do not correspond to 

174 Source: GEOSTAT, “Energy Consumption in Households”, 2017  
175

 Source: 

VVT, 

“Manual 

for 

Firewood 

Production, 

2008, 

http://www.biomasstradecentre2.eu/data/upload/D5_5_Manual_firewood_production_biohousing.pdf 

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other fuels. To allow comparability between firewood, we estimate the cost of firewood required 
to produce the same energy as natural gas being used by households in Georgia.  

Figure A. 56: Calculation of natural gas equivalent price 

Table A. 66 below presents the values used to calculate the equivalent natural gas price. 

Table A. 66: Values applied to calculate LNG equivalent price 

Item 

Average HH natural gas consumption in Georgia (m3) 
GCV for natural gas in Georgia (MJ/m3) 
Gas heater efficiency 
GCV for firewood in Georgia (MJ/m3 firewood) 
Firewood stove efficiency 
Firewood cost in Georgia (EUR/m3 firewood) 
Annual cost for firewood per HH (EUR) 
Equivalent natural gas price (EUR/1000 m3) 
A3.2.4. Step 2: Calculation of costs for fuel switching 
Fuel switching from firewood to natural gas would require development of a gas installation  at 
the end customer (service line and internal installation), while the gas retail price would have to 
be discounted compared to that of alternative fuels, so that the consumer can be incentivised to 
switch.  

Value 
1,100174 
35.0176 
90%177 
7,800174 
30%177 
20.8174 
308.0 
280.0 

The approach applied to calculate the costs (including incentives), for switching from firewood to 
gas, is presented in Figure A. 57 below. 

176 Source: GEOSTAT, Energy Balance 2018  
177 Assumption based on input requirements of such equipment 

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Figure A. 57: Calculation of costs for fuel switching 

The calculations require assumptions concerning the desired incentives of the end user, i.e. the 
payback period of internal installation costs and discounts on gas price. The values used in the 
calculation are presented in Table A. 67. 

Table A. 67: Values applied to calculate gas switching costs 

Item 
Cost of gas installation (EUR) 
Payback period (years) 
Uplift for end consumer incentive (%) 
Average HH natural gas consumption in Georgia (m3/yr) 
Fuel switching cost (EUR/1000 m3) 
A3.2.5. Step 3: Calculation of Distribution system costs 
As  the  examined  towns  are  not  gasified,  a  new  gas  distribution  system  has  to  be  developed, 
operated and maintained, to supply end consumers with gas.  

Value 
3,000178 (internal installation plus connection) 
10178 
20% (of competing fuel price) 178 
1,100174 
328.7 

As a benchmark for the distribution costs, we apply the 2019 approved distribution tariff of Socar 
Georgia  Gas  LLC  (68.3  EUR/1000m3) 179.  The  particular  DSO  has  been  selected  due  to  its 
extensive  expansion  plan  (obligation  under  the  distribution  license)  that  resulted  in  recent 
gasification of new regions. 

A3.2.6. Step 4: Calculation of small-scale receiving facility service fee 
The  service  charge  for  the  use  of  the  small-scale  LNG  receiving  facility  (unloading,  storage, 
regasification)  is  calculated  as  the  present  value  of  the  required  annual  revenues  (including 
recovery of all the facility’s investment costs and operating expenses and a return on the assets) 

178 Estimates based on relevant values in distribution systems of EU countries 
179 Source:  GNERC,  “Report  on  Activities  of  2018”,  2019.  The  tariff  applied  is  indicative,  used  for  the  high-level 
calculations. The actual tariff of the distribution system can be quite different, depending on the system’s characteristics, 
size and utilization. 

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per volume of regasified gas, for the full duration of the facility’s life cycle. The approach applied 
to calculate the service charge for the receiving facility is presented in Figure A. 58.  

Figure A. 58: Calculation of service charge for receiving facility 

The calculation of gas consumption for each town to be gasified (Table A. 68) is based on the 
population and average consumption per household. The assumed penetration of gas is based 
on the experience from mature gas markets, and not the current penetration in Georgia; gradual 
penetration from 30% to 70% in 4 years is assumed.  

Table A. 68: Calculation of gas consumption per gasified town 

Item 

Population180 
Persons per HH 
Average HH natural gas consumption 
in Georgia (m3/yr) 
Penetration rate 
Annual  gas 
at 
maximum penetration (70%) (mcm) 

consumption 

Chiatura 
12,803 

Oni 
2,656 

Value per Town 
Aspindza 
2,793 
3 

1,100174 

Borjomi  Mestia 
1,973 
10,546 

Gradual penetration: Y1: 30% | Y2: 40% | Y3: 55% | Y4: 70% 

3.29 

0.68 

0.72 

2.71 

0.51 

A small-scale receiving facility has to be installed in each distribution system, to allow supply of 
the concerned end consumers. The sizing of each receiving facility depends on the gas volumes 
required in the town, and especially the gas storage needs, as the storage capacity is the main 
cost driver for the facility. Given that gas consumption in householders is highly seasonal (80% 

180 Source: GEOSTAT, “Population by regions and self-governed units”, 2018 

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of  annual  demand  corresponds  to  the  November-April  period179),  storage  capacity  must  be 
designed to cover peak winter demand. In the examined town of Chiatura, considering the 80% 
annual demand in winter period, average daily demand in winter is estimated at 14,600 m3/d. The 
receiving  facility  for  Chiatura  is  assumed  to  have  LNG  storage  capacity  of  350  m3,  allowing 
sufficiency for 14 days. 

The benchmarks and assumptions used in the calculations of the service charge for the small-
scale receiving facility in Chiatura are presented in Table A. 69.  

Table A. 69: Values applied to calculate service charge for receiving facility 

Small-scale facility investment costs (EUR) 
Payback period (years) 

Item 

Expected rate of return on investment / discount rate 

Operating expenses 
Regasification service charge (EUR/1000 m3) 

Value 
950,000 (for 350 m3 storage)181 
10 (depreciation rate 10%) 
10% (assuming that the infrastructure will be 
regulated and operated by DSO) 
5% of investment costs182 
70.40 

A3.2.7. Step 5: Calculation of transportation cost for LNG truck 
The approach applied to calculate the cost for transporting LNG from its source (LNG terminal or 
liquefaction facility) to the receiving facility is the same with the one presented in Figure A. 49, in 
Section A2.4.6. 

Given that the same LNG trucks will be used to supply all gasified towns, the estimated costs 
should  cover  transportation  of  LNG  to  all  regions.  The  number  of  trips  to  each  of  the  towns 
depends  on  the  corresponding  consumption.  Table  A.  70  presents  the  LNG  trucks’  travel 
requirements (distance weighted with gas volume transported) to each town, starting from an LNG 
terminal in the Black Sea or a liquefaction facility located in the middle of the country.  

Table A. 70: LNG truck travel requirements from LNG terminal and liquefaction facility 

Distance 
(one-way) 
(km) 
170 
220 
270 
225 
200 

LNG Terminal 
Volumes 
transported 
(‘000 m3 LNG) 
5.5 
1.1 
1.2 
4.5 
0.9 
13.2 

Weighted 
distance 
(km) 
71 
19 
25 
77 
13 
204 

Chiatura 
Oni 
Aspindza 
Borjomi 
Mestia 
TOTAL 

Distance 
(one-way) 
(km) 
73 
100 
206 
130 
221 

Liquefaction Facility 
Volumes 
transported 
(‘000 m3 LNG) 
5.5 
1.1 
1.2 
4.5 
0.9 
13.2 

Weighted 
distance 
(km) 
30 
9 
19 
45 
14 
116 

181 Estimate based on storage investment cost range of 800 – 3000 USD/m3 (IGU, “2012 – 2015 Triennium Work Report 
–  Small  Scale  LNG”,  2015).  It  is  assumed  that  a  3,000  USD/m3  unit  cost  is  required  to  cover  all  facility  expenses 
(storage tanks, piping, vaporizers, control system, operating room, etc.) 
182 Assumption based on regasification terminals 

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The assumptions and benchmarks applied in the calculation of the LNG transportation costs are 
presented in Table A. 71. 

Table A. 71: Values applied to calculate LNG transportation cost 

Item 

Truck cost (EUR) 
Life cycle of truck (years) 
Expected rate of return on investment / discount rate 
Variable cost (EUR/km) 
LNG truck capacity (m3(LNG)) 
Distance per round trip from LNG terminal (km) 
Distance per round trip from liquefaction facility (km) 
Annual volumes of LNG transported (thousand m3 LNG) 
LNG transportation cost from LNG terminal (EUR/1000 m3) 
LNG transportation cost from liquefaction (EUR/1000 m3) 

Value 
620,000148 (cost for two trucks) 
8 (depreciation rate 13%)148 
20% 
1.45148 
50148 
408 
232 
13.2 
49.9 
38.8 

A3.2.8. Steps 6a-7a: Calculation of LNG truck loading cost at neighboring 
terminals 
Not relevant in this case study. 

A3.2.9. Steps 6b-7b: Calculation of LNG truck loading cost at terminals in 
Eastern Partner countries 
As  in  the  case  of  LNG  as  fuel  for  long-haul  trucks  the  LNG  truck  loading  costs  for  the  LNG 
receiving terminal are assumed to be similar to those for Klaipeda (48 EUR/1000 m3), and for the 
LNG liquefaction plant similar to those defined for Świnoujście (10.4 EUR/ 1000 m3). 

In the case of the liquefaction plant, a charge for liquefaction service must also be included in the 
calculations (corresponding to the liquefaction terminal tariff calculated in Section A2.3.5). 

A3.2.10. Steps 6c-7c: Calculation of Liquefaction cost at mini liquefaction 
facility 
The  approach  applied  to  calculate  the  liquefaction  cost  is  the  same  with  the  one  presented  in 
Figure A. 54, for the case of LNG as fuel for long-haul trucks. 

The annual volumes of LNG produced are equal to the gas volumes required for all gasified towns. 

The assumptions and benchmarks applied in the calculation are presented in Table A. 72. 

Table A. 72: Values applied to calculate gas liquefaction cost 

Item 
Liquefaction facility investment cost (EUR) 
Life cycle of truck (years) 
Expected  rate  of  return  on  investment  / 
discount rate 
Operating expenses 
Liquefaction cost (EUR/1000 m3) 

Value 
7,700,000 (for capacity of 16 tons/d)162 
20 (depreciation rate 5%) 
10% (due to its importance for the market, it is assumed 
that a single regulated facility will be developed) 
2% of investment costs163 
146.8 

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A3.2.11. Results of analysis 
In this case study, the costs for switching from firewood to gas (including gas installation costs 
and a 20% price differential incentive) are higher (329 EUR/1000m3) than the gas equivalent price 
for firewood (280 EUR/1000m3). Under these conditions, use of gas for the examined towns is 
not considered attractive. 

A3.3. Netback  analysis  for  LNG  supply  to  off-grid  individual 
consumers  
A3.3.1. Analysis approach 
Figure A. 59 outlines the process of netback analysis for deriving the competitive LNG price in an 
Eastern Partner country in the case LNG is used as a transportation modality of natural gas to an 
off-grid  final  consumer,  such  as  a  farming  facility  or  mining  facility  located  away  from  the 
transmission system.  

The starting point (Step 1) for the analysis is the equivalent natural gas price to the price that end-
customers pay, in the Eastern Partner country examined, for the alternative fuel, for the specific 
use. It is noted that the equivalent gas price takes into account the efficiency of natural gas versus 
the competing fuel. From this equivalent gas price, all costs to arrive at the competitive price of 
LNG at the source are sequentially estimated and subtracted: costs of retrofitting equipment to 
burn gas (Step 2), infrastructure cost for a small scale unloading, storage and regasification facility 
at  the  site  of  the  consumer  (Step  3),  transportation  costs  of  LNG  by  the  LNG  trucks  to  the 
regasification facility (Step 4), and the cost of loading LNG to trucks at the source or the costs of 
liquefaction of gas from the pipeline in the case of a mini liquefaction facility (Steps 5 – 6). 

As in the other LNG options, there are three potential LNG supply variants from the source to the 
regasification terminal, including: 

a.  (Steps 5a and 6a): The LNG trucks load and transport LNG from a terminal outside the 

Eastern Partner country.  

b.  (Steps 5b and 6b): The LNG trucks load and transport LNG from a terminal in the Eastern 
Partner  country  (regasification  or  liquefaction  terminal),  provided  it  is  feasible  for  the 
country to have its own terminal. 

c.  (Steps 5c and 6c): A mini liquefaction facility is installed to convert pipeline gas to LNG, 

which is then loaded into LNG trucks for delivery to end-customers.  

The resulting LNG price from the netback analysis is the price that needs to be compared to the 
regional price for spot LNG deliveries (in case LNG is sourced from a terminal) and/or the price 
of piped natural gas (in case LNG is produced using a mini liquefaction facility), so as  to ascertain 
whether LNG is competitive to prices of competing fuels for off-grid end-customers in the Eastern 
Partner country concerned.   

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Figure  A. 59: Netback analysis to estimate competitive LNG price at the source, for LNG used to 
supply off-grid consumers 

It is noted that the prices of competing fuels used in the analysis exclude VAT, but are inclusive 
excise taxes or any other taxes applied. On the other hand, it is assumed that the sourced LNG 
used to supply the off-grid consumer will be exclusive of any taxes. Inclusion of taxes on the LNG 
price would decrease its competitiveness vis-à-vis the competing fuel. 

A3.3.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
use of LNG to supply off-grid consumers is an applicable option for Ukraine.  

The LNG supply variants applicable to Ukraine include supply from the Świnoujście LNG terminal 
and Klaipeda FSRU and LNG reloading station, an LNG receiving terminal developed in Ukraine, 
and a mini liquefaction facility connected to the Ukrainian transmission system. 

The  attractiveness  of  this  LNG  option  may  differ  for  each  individual  off-grid  consumer,  as  the 
particular characteristics of the consumer (competing fuel used, consumption requirements and 
distance from the system) determine whether switching to natural gas would be viable.  

In this Study we provide an indicative example, for supply of LNG to a regasification facility of an 
agriculture  site  located  in  the  southern  part  of  Ukraine,  that  cannot  be  connected  to  the 
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transmission system, due to the lack of gas pressure reduction station capacity. It is assumed 
that the current fuel used is LPG. The agriculture site operates corn driers that require total natural 
gas consumption of 2,700 m3/h. The average drying season is from September – November, i.e. 
70-80  days,  during  which  the  driers  would  operate  on  a  continuous  basis.  Consequently,  the 
annual gas consumption of the site is estimated at 5,184,000 m3/yr. 

Based on this context, the calculations for each of the netback analysis steps are described in the 
sections below. 

A3.3.3. Step 1: Calculation of natural gas equivalent price 
The  approach  applied  to  calculate  the  natural  gas  price  equivalent  to  that  of  LPG  at  the  end-
consumer is presented in Figure A. 60 below.  

Figure A. 60: Calculation of natural gas equivalent price 

Table A. 73 below presents the values used to calculate the equivalent natural gas price. 

Table A. 73: Values applied to calculate LNG equivalent price 

Item 

LPG price (EUR/kg)183 
GCV for LPG in Ukraine (MJ/kg)184 
GCV for firewood in Georgia (MJ/m3)185 
Equivalent natural gas price (EUR/1000 m3) 

Value 
0.75 
46.9 
31.8 
508.5 
A3.3.4. Step 2: Calculation of costs for fuel switching 
It is assumed that the existing driers used are in need for replacement, and therefore the same 
investment  requirements  are  applied  for  new  infrastructure  of  either  LPG  or  natural  gas  (the 
additional costs for an LNG receiving facility required to use natural gas is examined in Step 3 of 
the analysis). 

Furthermore, due to the significant price differential of LPG and natural gas, it is assumed that no 
additional price incentives are necessary for the consumer to switch to gas.  

183 Source: https://index.minfin.com.ua/ua/markets/fuel/detail/ (accessed 1/11/2019) 

184 Based on Ukrainian Standards DSTU 4047-2001 
185 Based on Ukrainian Standards GOST 5542-2014 

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A3.3.5. Step 3: Calculation of small-scale receiving facility cost 
The approach applied to calculate the cost for the small-scale LNG receiving facility (unloading, 
storage, regasification) is presented in Figure A. 61. As this facility will be owned and operated 
by the consumer, no additional return on the assets is estimated. 

Figure A. 61: Calculation of cost for receiving facility 

The size of the small-scale receiving facility is driven by the daily gas needs during the drying 
season (64,800 m3/d). An LNG storage of 480 m3 is assumed, allowing refilling every 4 days. 

The benchmarks and assumptions used in the calculations are presented in Table A. 74.  

Table A. 74: Values applied to calculate service charge for receiving facility 

Item 

Small-scale facility investment costs (EUR) 
Payback period (years) 
Operating expenses 
Annual gas volumes (m3/yr) 
Regasification cost (EUR/1000 m3) 

Value 
1,300,000 (for 480 m3 storage)181 
10 (depreciation rate 10%) 
5% of investment costs182 
5,184,000 
37.6 

A3.3.6. Step 4: Calculation of transportation cost for LNG truck 
The approach applied to calculate the cost for transporting LNG from its source (LNG terminal or 
liquefaction facility) to the receiving facility is the same with the one presented in Figure A. 49, in 
Section A2.4.6. 

The assumptions and benchmarks applied in the calculation of the LNG transportation costs are 
presented in Table A. 75. Depending on the supply variant, a different number of LNG trucks is 
required to cover demand needs; three trucks will be required to cover the needs of the facility for 
its 80 days of operation from the terminals outside the country due to the large distances to be 
covered, two trucks are sufficient to transport supplies from the terminal in Ukraine, an a single 

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truck from a liquefaction terminal near the facility. The round-trip distance for each LNG supply 
variant is depicted in the Table. 

Table A. 75: Values applied to calculate LNG transportation cost 

Item 

Truck cost (EUR) 

Life cycle of truck (years) 
Expected  rate  of  return  on  investment  / 
discount rate 
Variable cost (EUR/km) 
LNG truck capacity (m3(LNG)) 
Distance per round trip (km) 
Annual volumes of LNG transported 
LNG transportation cost (EUR/1000 m3) 

Values per LNG supply variant 

Świnoujście 
Klaipeda 
930,000148 (cost for three 
trucks) 

Ukraine 

Liquefaction 

620,000 

310,000 

8 (depreciation rate 13%)148 

20% 

1.45148 
50148 

8,637 

200 

37.9 

3,600 

2,800 

216.6 

177.8 

50 

16.2 

A3.3.7. Steps 5a/b-6a/b: Calculation of LNG truck loading cost  
The truck loading costs for Świnoujście and Klaipeda LNG terminals are applied, as presented in 
Table A. 76 below. 

Table A. 76: Values used for LNG truck loading 

Terminal 

Świnoujście LNG terminal 

Klaipeda LNG terminal 

Ukraine LNG terminal 

Truck loading cost (EUR/1000m3) 
10.4 
48 (including transportation from terminal to 
reloading station and truck loading) 
48 (as in Klaipeda) 

A3.3.8. Steps 5c-6c: Calculation of Liquefaction cost at mini liquefaction 
facility 
The  approach  applied  to  calculate  the  liquefaction  cost  is  the  same  with  the  one  presented  in 
Figure A. 54, for the case of LNG as fuel for long-haul trucks. 

The size of the liquefaction facility should allow coverage of daily gas demand during the drying 
period (over 45 tons/d). For this reason, a liquefaction capacity of 50 tons/d is assumed. 

The assumptions and benchmarks applied in the calculation are presented in Table A. 77. 

Table A. 77: Values applied to calculate gas liquefaction cost 

Item 
Liquefaction facility investment cost (EUR) 
Life cycle of facility (years) 
Expected  rate  of  return  on  investment  / 
discount rate 
Operating expenses 
Liquefaction cost (EUR/1000 m3) 

Value 
12,500,000 (for capacity of 50 tons/d)162 
20 (depreciation rate 5%) 

20% 

2% of investment costs163 
470.2 

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A3.3.9. Results of analysis 
The results of the netback analysis for this case study, concerning the maximum supply price of 
LNG at the receiving terminals and natural gas at the entry of the mini liquefaction facility, are 
presented in Table A. 78 below.  

Table A. 78: Calculated maximum competitive LNG/gas price at the source per supply variant  

Item 

Świnoujście  Klaipeda 

LNG supply variant 
Ukraine 

Liquefaction 

Equivalent natural gas price (EUR/1000 m3) 
Regasification cost (EUR/1000 m3) 
LNG transportation cost (EUR/1000 m3) 
Truck loading / liquefaction cost (EUR/1000 m3) 
Maximum LNG/gas price at the source 
(EUR/1000 m3) 

508.5 
- 37.6 

- 216.6 
- 10.4 

- 177.8 
- 48.0 

- 37.9 
-48.0 

- 16.5 
- 470.2 

243.9 

246.1 

386.0 

-15.8 

A3.4. Netback analysis for LNG as fuel for ships  
A3.4.1. Analysis approach 
Figure A. 62 outlines the process of netback analysis for deriving the competitive LNG price in an 
Eastern Partner country for LNG to be used as fuel by  ships (either converting ships currently 
running on oil products to run on LNG, or constructing newbuilds that run on LNG).  

Figure A. 62: Netback analysis to estimate competitive LNG price at the source, for LNG as fuel for 
ships, in competition with oil products 

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The starting point (Step 1) for the analysis is the equivalent LNG price to the price/cost paid by 
ships, for the existing fuel (MGO, HFO), in the Eastern Partner country examined. It is noted that 
the equivalent LNG price takes into account the efficiency of LNG as a fuel versus the existing 
fuel.  From this  equivalent  LNG  price,  all  costs  to  arrive at  the  competitive price  of  LNG  at  the 
source are sequentially estimated and subtracted: costs of retrofitting the ship or additional cost 
for a newbuild LNG-fuelled ship (Step 2), bunkering costs at the LNG terminal or port (Step 3),  
and, in case LNG has to be delivered to the port via LNG trucks, the cost of transporting LNG 
(Step 5) and of loading it to trucks at the source or the costs of liquefaction of gas from the pipeline 
(Steps 5 – 6). 

Three supply variants can be considered, each variant having different costs to be incurred under 
Steps 4 and 5:   

a.  (Steps 4a and 5a): The LNG trucks load and transport LNG from a terminal outside the 

Eastern Partner country.  

b.  (Steps 4b and 5b): LNG for bunkering is directly delivered to an LNG terminal (or port) in 
the Eastern Partner country, provided it is feasible for the country to have its own terminal. 
This allows direct bunkering from the terminal or port, without any additional transportation 
costs incurred. 

c.  (Steps 5c and 6c): A mini liquefaction facility is installed to convert pipeline gas to LNG, 

which is then loaded into LNG trucks for delivery to the port.  

The resulting LNG price from the netback analysis is the price that needs to be compared to the 
regional price for spot LNG deliveries (in case LNG is sourced from a terminal) and/or the price 
of  piped  natural gas (in case  LNG  is  produced using  a  liquefaction facility),  so as to  ascertain 
whether  LNG  is  competitive  to  prices  of  other  bunkering  fuel  for  the  Eastern  Partner  country 
concerned.   

It is noted that the prices of competing fuels used in the analysis exclude VAT, but are inclusive 
excise taxes or any other taxes applied for the fuel. On the other hand, it is assumed that LNG 
used  for  transport  will  be  exclusive  of  any  taxes.  Inclusion  of  taxes  on  the  LNG  price  would 
decrease its competitiveness vis-à-vis the competing fuel.   

A3.4.2. Application in Eastern Partner countries 
Based on the Consultant’s analysis and the consultations with the countries’ stakeholders, the 
use of LNG as a fuel for ships is an applicable option for Azerbaijan, Belarus and Ukraine.  

The potential use of LNG as a bunkering fuel for existing ships in the region, to cover international 
obligations (IMO rule to the ships’ sulphur emissions from 3.5% to 0.5% as of 1/1/2020) competes 
with alternative solutions such as the use of scrubbers or low sulphur fuel oil. So far retrofitting of 
ships  in  operation  to  run  on  LNG  has  not  been  the  preferred  option  outside  Emission  Control 
Areas, as the retrofitting cost has been considered higher than that of alternative solutions. In this 
respect, and with cost being the driver to switch to LNG, the case of promoting the use of LNG in 
newbuilds appears to have more potential than retrofitting existing ships. 

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The attractiveness of this LNG option differs for each individual case of ship, as it depends on a 
number of factors, including the vessel’s size and type, age, service area, fuel used, refuelling 
pattern, prices of competing fuels, etc.  

In this Study we provide an indicative example, for the use of LNG in shipping.  The case of a 
newbuild 50,000 MT PANAMAX type vessel operating in the Black Sea, with LNG and MGO as 
competing fuels.  It  is  assumed  that  the  ship  will  perform  30  roundtrips  per  annum,  covering  a 
distance of  1,500  nautical  miles  per  roundtrip.  Bunkering  is  assumed  to take place  at  an  LNG 
terminal in Ukraine, consequently Steps 4 and 5 of the netback analysis (that concern costs for 
the transportation of LNG to ports via trucks) are omitted186. 

Based on this context, the calculations for each of the netback analysis steps are described in the 
sections below. 

A3.4.3. Step 1: Calculation of LNG equivalent price 
The approach applied to calculate the LNG price equivalent to that of MGO is presented in Figure 
A. 63 below.  

Figure A. 63: Calculation of LNG equivalent price 

The fuel price used to perform the case study is based on the price level of MGO at the Istanbul 
port,  as  an  indicative  competing  price.  Table  A.  79  presents  the  values  used  to  calculate  the 
equivalent LNG price.  

Table A. 79: Values applied to calculate LNG equivalent price 

Item 

Bunker fuel price (EUR/MT) 
Fuel consumption (MT/Nautical Mile) 
LNG consumption (MT/Nautical Mile) 
Equivalent LNG price EUR/1000 m3  

Value 
600187 
0.063188 
0.051188 
566.9 

186 The calculation of costs for steps 4 and 5 would follow the same approach as the one in Sections A3.1.6, A3.1.7 
and A3.1.9. 
187 Assumption based on MGO price at the Istanbul port 
188 Source: Sangsoo Hwang et al. (Journal of Marine Science and Engineering), “Life Cycle Assessment of LNG Fuelled 
Vessel in Domestic Services”, 2019. Note: Values correspond to a low service speed of 14 knots. Higher speed would 
lead to increase in fuel consumption. 

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A3.4.4. Step 2: Calculation of costs for fuel switching 
The cost of a newbuild running on LNG is higher than that of ships using conventional bunkering 
fuels. The recovery of this additional cost should be taken into consideration in the analysis of the 
option’s financial viability. The approach applied to include this additional cost in the analysis is 
presented in Figure A. 64. 

Figure A. 64: Calculation of costs for fuel switching 

The applied assumptions and benchmarks are presented in Table A. 80.  

Table A. 80: Values applied to calculate LNG switching costs 

Item 

Additional cost for newbuild LNG ship (EUR) 
Payback period requirement (years) 
Number of annual round-trips 
Distance per round-trip (Nautical Miles) 
LNG consumption (MT/Nautical Mile) 
LNG switching costs EUR/1000 m3 

Value 
9,000,000189 
15 years189 
30 
1,500 
0.051 
218.4 

A3.4.5. Step 3: Definition of bunkering costs 
As  a  benchmark  for  the  cost  of  bunkering  at  the  LNG  terminal,  we  use  the  fee  charged  for 
bunkering of vessels at the Klaipeda reloading facility, 24 EUR/1000 m3. 

Potential environmental discounts offered in the port tariffs for LNG-fuelled ships are not taken 
into consideration in the analysis of this case study.  

189 Based on shipping sector sources 

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A3.4.6. Results of analysis 
The results of the netback analysis for this case study, concerning the maximum supply price of 
LNG at the terminal for bunkering purposes, are presented in Table A. 81. 

Table A. 81: Calculated maximum competitive price for LNG bunkering at the LNG terminal 

Item 

Equivalent natural gas price (EUR/1000 m3) 
LNG switching costs (EUR/1000 m3) 
LNG bunkering costs (EUR/1000 m3) 
Maximum LNG price at the terminal (EUR/1000 m3) 

Value 
566.9 
-218.4 
-24 
324.6 

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Annex 4: Economic Analysis – Gas-to-Gas Competition  

A4.1. Economic  analysis  for  LNG  receiving  terminal  in  Eastern 
Partner country 
A4.1.1. Analysis approach 
The aim of the economic (cost-benefit) analysis to assess whether the costs for developing and 
operating  an  in-country  LNG  receiving  terminal  are  outweighed  by  its  potential  benefits  to  the 
economy and society. The economic analysis is applied only for the cases that, according to the 
netback  analysis,  are  not  viable,  and  therefore  additional  benefits  for  the  society  should  be 
achieved, for the LNG market option to be implemented.     

The approach followed is in accordance with the EC CBA Guide for infrastructure investments190. 

The costs and monetized benefits assessed are the following: 

  Costs:  

Investment costs for the development of the terminal; 

o 
o  Annual operating costs; 
o  Premium paid to import LNG to the market, in case the supply price of LNG to the 
market (including all transportation costs) is higher than that of piped gas, and LNG 
is imported only for security of supply purposes. 

  Monetized benefits:  

o  Enhancement of security of supply, by examining the economic impact of reducing 

gas demand curtailment in case of a supply disruption; 

o  Reduction of energy costs for final consumers, in case the supply price of LNG to 
the market (including all transportation costs) is lower than that of piped gas. 

The monetization of security of supply benefits covers only the cases of short-term disruptions 
that cannot be addressed with the existing infrastructure. In case long-term supply gaps emerge 
in the market, due to the lack of sufficient infrastructure, the alternative options to address them 
(including development of the LNG terminal) should be analysed in detail to identify the optimal 
and cost-effective solution for the market. Therefore, long-term gaps are not examined in terms 
of security of supply within the frame of this Study.  

For the examined scenarios in which the assumed LNG import price at the terminal is higher than 
the market price, and therefore not competitive, it is assumed that the operation of the terminal 
will  be  only  for  security  of  supply  purposes.  In  this  case,  the  terminal  annually  receives  LNG 
volumes sufficient to cover a supply disruption in the market, which are sold at a loss in case the 
disruption is not realised.   

190 DG Regio (2015) EC CBA Guide for infrastructure investments, available at: 
https://ec.europa.eu/regional_policy/sources/docgener/studies/pdf/cba_guide.pdf  

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The economic analysis was carried out for a 20-year period of the LNG terminal operation. As the 
development of the infrastructure (FSRU and supporting infrastructure) would require at least 2-
3 years,  we assume that  imports  of LNG  in  the market  would commence in  2023,  and the full 
period of the analysis is 2023 – 2042.  

The analysis results in the estimation of the key economic performance indicators; the Economic 
Net Present Value (ENPV), Economic Rate of Return (ERR), and Benefit-to-Cost ratio (B/C). A 
social  discount  rate  of 4%  has  been  applied  in the  calculations,  in  line with  those  used  by the 
Energy Community in the PECI evaluation191. 

Figure A. 65: Assessment of costs and benefits 

It is noted that the analysis carried out is high-level, based on assumptions on gas/LNG supply 
prices  and  market  demand  for  LNG,  without  examining  dynamic  supply-demand  curves.  The 
results of this analysis can be used to draw preliminary conclusions, whereas for a more detailed 
view of the projects’ economic performance modelling of the markets evolution is required. 

A4.1.2. Application in Eastern Partner countries 
Economic analysis was conducted for the LNG terminal in Georgia, supplying LNG for the local 
market, and the terminal in Ukraine, supplying LNG to both Ukraine and Moldova. For the purpose 
of  the  analysis,  the  price  of  LNG  in  the  Black  Sea  is  assumed  to  be  220  EUR/  1000  m3, 
corresponding to a 5% increase to the average price of LNG at the Greek Revythoussa terminal 
for Q2 2019 (210 EUR/1000m3, source: DG Energy, “Gas Market Report Q2 2019”). 

191 REKK, “Final report on Assessment of the candidate Projects of Energy Community Interest (PECI) and Projects 
for Mutual Interest (PMI)”, 2018 

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Georgian LNG terminal 

The netback analysis for the Georgian LNG terminal has shown that, with the examined terminal 
utilization and assumed LNG price in the Black Sea, LNG is not competitive to existing supply 
sources, in case import prices remain at the current level or moderately increase. 

The terminal’s benefit for enhancing security of supply is assessed by examining a disruption of 
Azeri gas supplies to the market during a peak demand period. 

Economic analysis was performed for the following price and terminal utilization scenarios: 

 

 

Import  price  of  Azeri  gas  to  Georgia  (including transmission  tariff)  of  206  EUR/1000 
m3. As the assumed LNG price is higher, and thus not competitive, the terminal will be 
utilized  only  for  security  of  supply  purposes,  to  cover  potential  demand  curtailment 
(supply gap) in case of disruption in the Azeri imports. The volumes used for security 
of supply correspond to the annual potential curtailed demand are estimated in Section 
A4.1.3. 

Import  price  of  Azeri  gas  to  Georgia  (including transmission  tariff)  of  256  EUR/1000 
m3. As the assumed LNG price is lower, sales of LNG in the market equal to 30%, 50% 
and 70% of the terminal’s utilization are examined. 

Ukrainian LNG terminal 

The netback analysis for the Ukrainian LNG terminal has shown that, with the examined terminal 
utilization and assumed LNG price in the Black Sea, LNG is not competitive to existing supply 
sources  in  Ukraine,  in  case  import  prices  are  at  a  low  or  average  historic  price.  Furthermore, 
supply of LNG in the Moldovan market is not economically viable, as current price levels are low. 

The terminal’s benefit for enhancing security of supply is assessed by examining a disruption of 
Russian transit through Ukraine that would affect the import capacity of Ukraine and the supplies 
to Moldova.    

Economic analysis was performed for the following price and terminal utilization scenarios: 

 

 

Import price of piped EU gas to Ukraine (including transmission tariff) of 198 EUR/1000 
m3. As the assumed LNG price is higher, and thus not competitive, the terminal will be 
utilized only for security of supply purposes in Ukraine and Moldova, to cover potential 
demand curtailment in case of disruption in Russian transit that affects the capacity to 
import gas. The volumes used for security of supply correspond to the annual potential 
curtailed demand are estimated in Section A4.1.3. 

Import price of piped EU gas to Ukraine (including transmission tariff) of 241 EUR/1000 
m3. As the assumed LNG price is lower, sales of LNG in the market equal to 30%, 50% 
and 70% of the terminal’s utilization are examined. 

A4.1.3. Calculation of demand curtailment in case of disruption 
For  each  examined  country  (Georgia,  Ukraine,  Moldova)  we  examine  a  2-week  disruption 
scenario at peak demand. The supply gap is calculated after supplies from remaining sources, 
storage and indigenous production are taken into consideration. 

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Georgia 

Projected peak daily gas demand in the Georgian market is 16.1 mcm/d by 2025 and 18.6 mcm/d 
by 2030192, which corresponds to almost double the average daily gas consumption of those years 
(Table A. 82). The ratios presented in the Table below are applied on the annual gas demand 
forecasts (Figure A. 20) to estimate the peak daily demand for the period 2020 – 2030. 

Table A. 82: Ratio of peak daily to average demand for Georgia 

Annual demand (mcm/yr)192 
Average daily demand (mcm/d) 
Peak daily demand (mcm/d) 
Peak / average ratio 

2025 
2,999 
8.2 
16.1 
1.96 

2030 
3,483 
9.5 
18.6 
1.95 

With the Azeri gas supplies disrupted, and considering that indigenous production is negligible, 
the only potential source for the market is Russian gas received though the Georgian off-take of 
the North-South Pipeline, that can amount up to 4.5 mcm/d192. The estimated evolution of daily 
peak demand and the curtailed demand, for the period 2020 – 2030 is presented in Figure A. 66. 
As  longer-term  demand  projections  are  not  available,  for  the  remaining  period  of  the  20-year 
economic analysis, 2031 – 2042, we assume the same demand curtailment as in 2030. 

Figure A. 66: Estimated evolution of peak daily demand and demand curtailment for Georgia 

The reduction of curtailed demand by the terminal impact for a 2-week disruption is presented in 
Table A. 83. 

Table A. 83: Curtailed demand in Georgia for a 2-week period for 2023 – 2042 

Daily demand curtailment (mcm/d) 
2-week demand curtailment (mcm) 

2023 
10.6 
149.1 

2027 
12.5 
175.2 

2032 
14.1 
197.4 

2037 
14.1 
197.4 

2042 
14.1 
197.4 

192 Source: Department of Strategic Planning and Projects of GOGC 

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Ukraine 

The network development plans prepared  for the transmission system (UTG193) and the storage 
facilities (SSO194) include only annual demand forecasts (Figure A. 34 and Figure A. 35), and not 
peak daily projections. To analyse the demand curtailment in Ukraine, we estimate future peak 
demand on the basis of historic observations (Table A. 84). The average of the ratios presented 
in the Table below (2.33) is applied on the annual gas demand forecasts (Figure A. 34 and Figure 
A. 35) to estimate the peak daily demand for the period 2020 – 2029.  

Table A. 84: Ratio of peak daily to average demand for Ukraine 

Annual demand (mcm/yr)195  
Average daily demand (mcm/d) 
Peak daily demand (mcm/d)196 
Peak / average ratio 

2016 
33,200 
91.0 
217.4 
2.39 

2017 
31,900 
87.4 
198.1 
2.27 

In case of disruption of Russian gas transit through Ukraine, the import capacity from EU will be 
affected significantly, as most of the capacity is interruptible, and dependent on the Russian flows 
to EU197: 

  Budince (Slovakia): 27 mcm/d firm capacity, 15.5 mcm/d interruptible capacity; 

  Beregdaroc (Hungary): 19.5 mcm/d interruptible capacity; 

  Hermanovice (Poland): 6.4 mcm/d interruptible capacity. 

Consequently, import capacity of 27 mcm/d would remain available. It is noted that the upcoming 
reverse flow  at IP Orlovka,  allowing  imports  of up  to  4.5 mcm/d from  Romania,  is  expected  to 
have  interruptible capacity,  while other  planned projects, such  as  the  planned  interventions  by 
FGSZ  at  the  Beregdaroc  IP  to  provide  16.8  mcm/d  of  firm  capacity,  or  the  interconnector 
Drozdovichi – Bilche Volytsia between Poland and Ukraine, have not received FID, and are thus 
not taken into consideration in the analysis. 

The levels of Ukrainian gas production typically remain constant throughout the year. Therefore, 
in  the  analysis  we  use  the  average  daily  production,  estimated  on  the  basis  of  the  annual 
production forecasts for the period 2020 – 2029 (Figure A. 34 and Figure A. 35). 

According to the UGS Development Plan 2020 – 2029, the design peak withdrawal rate of the 
Ukrainian  gas  storages  reaches  260  mcm/d.  However,  the  actual  maximum  deliverability  is 
significantly lower, mainly due to technical limitations (the Bilche-Volytsia UGS cannot reach its 
design withdrawal rate due to shortage in cushion gas), and the fact that the storages have been 
designed  for  seasonal  fluctuations  to  support  gas  transit,  and  not  for  peak  shaving  purposes. 

193 UTG, TYNDP 2019 – 2028 
194 UTG / SSO, USG Development Plan 2020 – 2029 
195 Source: Naftogaz website, (accessed 25/11/2019)  
196 Sources: Energy Community, Reports on the results of the security monitoring of natural gas supply during 2016 
and 2017  
197 Source: Input from UTG 

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Taking into consideration that high deliverability rates depends on reservoir pressure and normally 
declines over the withdrawal season, we assume a withdrawal rate of 100 – 150 mcm/d.  

The estimated evolution of daily peak demand and the curtailed demand, for the period 2020 – 
2028/29  are  presented  in  Figure  A.  67  and  Figure  A.  68  respectively  (assuming  a  storage 
withdrawal  rate  of  100  mcm/d).  As  longer-term  demand  projections  are  not  available,  for  the 
remaining period of the 20-year economic analysis, 2030 – 2042, we assume the same demand 
curtailment as in 2029. 

Figure A. 67: Estimated evolution of peak daily demand and demand curtailment for Ukraine (UTG) 

Figure A. 68: Estimated evolution of peak daily demand and demand curtailment for Ukraine (SSO) 

The  Figures  above  show  that  demand  is  curtailed  only  in  case  gas  production  follows  a 
conservative evolution path, as the one indicated in the  UGS Development Plan 2020 – 2029, 
and available maximum withdrawal rate for UGS is low. Given that this is the only case in which 
the LNG terminal would have an impact in security of supply, the corresponding curtailed volumes 
are further used in the economic analysis (Table A. 85). 

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Table A. 85: Curtailed demand in Ukraine for a 2-week period for 2023 – 2042 

Daily demand curtailment (mcm/d) 
2-week demand curtailment (mcm) 

Moldova 

2023 
- 
- 

2027 
1.5 
20.5 

2032 
3.3 
46.2 

2037 
3.3 
46.2 

2042 
3.3 
46.2 

To estimate the peak daily demand in the Moldovan market, we use the gas demand projections 
that  were  applied for the  evaluation  of the  2018 PECI  list. In  the  absence of  publicly  available 
daily demand data for Moldova, we apply the ratio of peak to average demand of Ukraine (2.33). 
The calculation results are presented in Table A. 86. 

Table A. 86: Calculation of peak daily demand for Moldova 

Annual demand (mcm/yr)198 
Average daily demand (mcm/d) 
Peak / average ratio 
Peak daily demand (mcm/d) 

2020 
965 
2.6 

6.2 

2025 
1,053 
2.9 
2.33 
6.7 

2030 
1,140 
3.1 

7.3 

Peak demand for the intermediary years is estimated by applying linear interpolation. As longer-
term  demand  projections  are  not  available,  for  the  remaining  period  of  the  20-year  economic 
analysis, 2031 – 2042, we assume the same demand curtailment as in 2030. 

In case  Russian  gas  supplies  are  disrupted,  Moldova  can  continue receiving  up  to  4.1  mcm/d 
through the extension of the Iasi (Romania) – Ungheni (Moldova) pipeline to Chisinau, which is 
currently under construction. 

The estimated evolution of daily peak demand and the curtailed demand, for the period 2020 – 
2030  is  presented  in  Figure A.  69. The gas  demand curtailment  used  to assess  the terminal’s 
impact for a 2-week disruption are presented in Table A. 87. 

Figure A. 69: Estimated evolution of peak daily demand and demand curtailment for Moldova 

198 REKK, “Final report on Assessment of the candidate Projects of Energy Community Interest (PECI) and Projects 
for Mutual Interest (PMI)”, 2018. The GCV used to convert to mcm is presented in Annex 7. 

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Table A. 87: Curtailed demand in Moldova for a 2-week period for 2023 – 2042 

Daily demand curtailment (mcm/d) 
2-week demand curtailment (mcm) 

2023 
2.4 
33.5 

2027 
2.8 
39.7 

2032 
3.2 
44.4 

2037 
3.2 
44.4 

2042 
3.2 
44.4 

A4.1.4. Definition of investment and operational costs 
The CAPEX and OPEX values used are the same with those used for the netback analysis of 
each  terminal,  presented  in  Table  A.  26  for  the  Georgian  terminal  and  in  Table  A.  27  for  the 
Ukrainian terminal.  

A 3-year period of terminal development is assumed in 2020 – 2022, with 20% of CAPEX used 
in the 1st year, 40% in the 2nd and 40% in the 3rd. 

A4.1.5. Monetization of impact on the cost of gas supplies 
Depending on the examined scenario for the price of imported gas, LNG may be: 

  More  expensive  than  piped  gas,  in  which  case  LNG  is  supplied  only  to  cover  the 
potential curtailed demand for each year. In these scenarios the cost of gas supplies 
in the market would increase, to enhance security of supply.  

  Cheaper than piped gas, in which case LNG can substitute piped gas, and reduce the 

cost of gas supplies. 

The  benefit/cost  of  LNG  supplies  is  determined  by  the  annual  volumes  of  LNG  landing  at  the 
terminal and the positive/negative price differential of LNG and imported piped gas. 

Georgian LNG terminal 

In the scenario that import price of Azeri gas remains at current levels (206 EUR/1000 m3), LNG 
at  the  assumed  price for  the  Black  Sea  (220  EUR/1000  m3)  would  be  14  EUR/1000  m3  more 
expensive.  The  LNG  terminal  in Georgia  has  been  assumed  to have a  send-out  capacity  of  1 
bcm/yr,  corresponding  to  2.7  mcm/d.  Consequently,  only  part  of  the  curtailed  demand  can  be 
covered by the terminal, 38.4 mcm for the duration of the 2-week disruption. The annual premium 
to be paid in the market to have LNG for security of supply is presented in Table A. 88. 

Table A. 88: Gas price increase in Georgia for current import price (supplies for security of supply) 

Security of supply needs (2-week 
demand curtailment) (mcm) 
Gas price increase (mil. EUR) 

2023 

38.4 

0.5 

2027 

38.4 

0.5 

2032 

38.4 

0.5 

2037 

38.4 

0.5 

2042 

38.4 

0.5 

In the  scenario, that  import  price  of  Azeri gas moderately  increases (256  EUR/1000  m3), LNG 
would be 36 EUR/1000 m3 cheaper. Table A. 89 below presents the assumed LNG volumes for 
each case of terminal utilization, and the corresponding benefit on gas prices.   

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Table A. 89: Gas price decrease in Georgia for 25% import price increase, per utilization rate 

Annual LNG volumes (mcm) 
Gas price decrease (mil. EUR) 

30% 
300 
10.8 

50% 
500 
18.0 

70% 
700 
25.2 

Ukrainian LNG terminal 

In the scenario of minimum import price (198 EUR/1000 m3), LNG at the assumed price for the 
Black Sea (220 EUR/1000 m3) would be 22 EUR/1000 m3 more expensive. The LNG volumes 
supplied  to  avoid  curtailment  are  estimated  as  the  aggregate  for  Ukraine  and  Moldova.  The 
annual premium to be paid in the market to have LNG for security of supply is presented in Table 
A. 90. 

Table A. 90: Gas price increase in Ukraine for minimum import price (supplies for security of supply) 

Security of supply needs in Ukraine 
(2-week demand curtailment) (mcm) 
Security of supply needs in Moldova 
(2-week demand curtailment) (mcm) 
Gas price increase (mil. EUR) 

2023 

- 

33.5 

0.7 

2027 

20.5 

39.7 

1.3 

2032 

46.2 

44.4 

1.9 

2037 

46.2 

44.4 

1.9 

2042 

46.2 

44.4 

1.9 

In  the  scenario  of  average  import  price  (241  EUR/1000  m3),  LNG  would  be  21  EUR/1000  m3 
cheaper.  Table  A.  91  below  presents  the  assumed  LNG  volumes  for  each  case  of  terminal 
utilization, and the corresponding benefit on gas prices.   

Table A. 91: Gas price decrease in Ukraine for average import price, per utilization rate 

Annual LNG volumes (mcm) 
Gas price decrease (mil. EUR) 

30% 
2,000 
10.8 

50% 
2,500 
18.0 

70% 
3,500 
25.2 

A4.1.6. Monetization of security of supply benefits 
The security of supply benefits of the LNG terminal corresponds to the elimination of the impact 
of a supply disruption. To monetize the impact of demand curtailment, we use the Value of Lost 
Load for  the  market.  VoLL  is  calculated  as  the  ratio  of the  country’s  GDP  to the  value  of  final 
energy consumption required to produce it199. 

The VoLL applied to each country is presented in Table A. 92 below. 

199 A  typical  simplified  approach  to  estimate  VoLL,  instead  of  resorting  to  economy-wide  surveys  to  assess  the 
consumers’ willingness to pay. 

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Table A. 92: VoLL calculated for each examined country 

GDP in 2017 (bil. EUR) 
Total Final Energy Consumption in 2017 (TWh) 
VoLL (EUR/MWh) 
VoLL (EUR/1000 m3) 

Georgia 
13.1200 
50.7 
257.3 
2,609 

Ukraine 
101.4201 
582.5 
174.2 
1,944 

Moldova 
8.6202 
31.6 
271.6 
3,096 

A  probability  for  the  occurrence  of  the  disruption  event  has  to  be  used  to  assess  the  risk  of 
demand curtailment. For this analysis, we apply a 5% probability (corresponding to a 1-in-20 years 
event), which is the probability used by ENTSOG in the Union-wide TYNDP and security of supply 
simulations. 

The benefits of security of supply are the same for all examined price scenarios and utilization 
rates of each terminal.   

Georgian LNG terminal 

The  LNG  terminal  in  Georgia  has  been  assumed  to  have  a  send-out  capacity  of  1  bcm/yr, 
corresponding to 2.7 mcm/d. Consequently, only part of the curtailed demand can be covered by 
the terminal, 38.4 mcm for the duration of the 2-week disruption. The calculation of the monetized 
security of supply benefit is presented in Table A. 93. 

Table A. 93: Security of supply benefit of Georgian LNG terminal 

Security of supply needs (2-week 
demand curtailment) (mcm) 
VoLL (EUR/1000 m3) 
Probability of disruption 
SoS benefit (mil. EUR) 

Ukrainian LNG terminal 

2023 

38.4 

2027 

38.4 

5.0 

5.0 

2032 

38.4 

2,609 
5% 
5.0 

2037 

38.4 

2042 

38.4 

5.0 

5.0 

The  LNG  terminal  in  Georgia  has  been  assumed  to  have  a  send-out  capacity  of  1  bcm/yr, 
corresponding  to  13.7  mcm/d.  Consequently,  the  capacity  is  sufficient  to  fully  address  the 
curtailed demand. The calculation of the monetized security of supply benefit is presented in Table 
A. 94. 

Table A. 94: Security of supply benefit of Ukrainian LNG terminal 

Security of supply needs in Ukraine 
(2-week demand curtailment) (mcm) 
VoLL in Ukraine (EUR/1000 m3) 
Probability of disruption 
SoS benefit for Ukraine (mil. EUR) 
Security of supply needs in Moldova 
(2-week demand curtailment) (mcm) 

2023 

- 

- 

33.5 

2027 

20.5 

2.0 

39.7 

2032 

46.2 

1,944 
5% 
4.5 

44.4 

2037 

46.2 

4.5 

44.4 

2042 

46.2 

4.5 

44.4 

200 Source: National Statistics Office of Georgia 
201 Source: State Statistics Service of Ukraine 
202 Source: National Bureau of Statistics of the Republic of Moldova 

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5.2 
5.2 

VoLL in Moldova (EUR/1000 m3) 
Probability of disruption 
SoS benefit for Moldova (mil. EUR) 
6.9 
Total SoS benefit (mil. EUR) 
11.4 
A4.1.7. Calculation of remaining net benefits (residual value) 
The period for which the economic analysis is conducted (20 years) is not in sync with the lifetime 
of the terminal (30 years). For this reason, a residual value has to be estimated for the remaining 
years  of  the  terminal’s  operation,  until  its  decommissioning  or  replacement.  To  estimate  the 
residual value, we assume that the annual net benefits of the terminal for years 21 – 30 are equal 
to those of the 20th year.  

3,096 
5% 
6.9 
11.4 

6.9 
11.4 

6.1 
8.1 

A4.1.8. Results of analysis 
Georgian LNG Terminal 

Figure A. 70 to Figure A. 73 below present the evolution of economic costs and benefits of the 
Georgian LNG terminal, for each price scenario and utilization rate. 

Figure A. 70: Evolution of economic costs / benefits for Georgian receiving LNG terminal, for current 
import price 

Figure A. 71: Evolution of economic costs / benefits for Georgian receiving LNG terminal, for 25% 
import price increase, 30% utilization rate 

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Figure A. 72: Evolution of economic costs / benefits for Georgian LNG terminal, for 25% import price 
increase, 50% utilization rate 

Figure A. 73: Evolution of economic costs / benefits for Georgian LNG terminal, for 25% import price 
increase, 70% utilization rate 

Table A. 95 presents the present values of the calculated economic costs and benefits for the 
Georgian LNG terminal. 

Table A. 95: Present value of economic costs and benefits for Georgian LNG terminal per examined 
scenario 

Examined utilization rate 
CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Residual value (Mil. EUR) 
Net benefits (Mil. EUR) 

Current 
import price 
Only SoS 
-216.8 
-6.7 
62.9 
0.4 
-160.3 

25% import price increase 

30% 
-224.8 
135.7 
62.9 
37.1 
10.8 

50% 
-230.9 
226.2 
62.9 
60.0 
118.2 

70% 
-236.9 
316.6 
62.9 
83.0 
225.6 

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Table A. 96 presents the economic indicators for the Georgian LNG terminal. 

Table A. 96: Economic indicators for Georgian LNG terminal per examined scenario 

Examined utilization rate 
ENPV (Mil. EUR) 
ERR 
B/C Ratio 

Current 
import price 
Only SoS 
-160.3 
N/A 
0.26 

25% import price increase 

30% 
10.8 
4.6% 
1.05 

50% 
118.2 
9.2% 
1.5 

70% 
225.6 
12.9% 
1.95 

Ukraine LNG Terminal 

Figure A. 74 to Figure A. 77 below present the evolution of economic costs and benefits of the 
Ukrainian LNG terminal, for each price scenario and utilization rate. 

Figure A. 74: Evolution of economic costs / benefits for Ukrainian LNG terminal, for minimum import 
price 

Figure A. 75: Evolution of economic costs / benefits for Ukrainian LNG terminal, for average import 
price, 30% utilization rate 

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Figure A. 76: Evolution of economic costs / benefits for Ukrainian LNG terminal, for average import 
price, 50% utilization rate 

Figure A. 77: Evolution of economic costs / benefits for Ukrainian LNG terminal, for average import 
price, 70% utilization rate 

Table A. 97 presents the present values of the calculated economic costs and benefits for the 
Ukrainian LNG terminal. 

Table A. 97: Present value of economic costs and benefits for Ukrainian LNG terminal per examined 
scenario 

Examined utilization rate 
CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Residual value (Mil. EUR) 
Net benefits (Mil. EUR) 

Minimum 
import price 
Only SoS 
-588.0 
-21.2 
123.5 
-11.1 
-496.7 

Average import price 

30% 
-647.8 
527.7 
123.5 
123.2 
126.6 

50% 
-663.0 
659.7 
123.5 
155.0 
275.2 

70% 
-693.4 
923.5 
123.5 
218.6 
572.2 

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Table A. 98 presents the economic indicators for the Ukrainian LNG terminal. 

Table A. 98: Economic indicators for Ukrainian LNG terminal per examined scenario 

Examined utilization rate 
ENPV (Mil. EUR) 
ERR 
B/C Ratio 

Minimum 
import price 
Only SoS 
-496.7 
N/A 
0.16 

Average import price 

30% 
126.7 
6.2% 
1.2 

50% 
257.2 
8.5% 
1.4 

70% 
572.2 
12.4% 
1.8 

A4.2. Economic analysis for regasified LNG supplied via pipeline 
from neighbouring EU LNG Terminals 
A4.2.1. Analysis approach 
The  aim  of  the  economic  (cost-benefit)  analysis  to  assess  whether  the  economic  costs  for 
importing  regasified  LNG  from  neighbouring  terminals  to  an  Eastern  Partner  country  are 
outweighed by its potential benefits to the economy and society.  

The overall approach is the same with the one described in Section A4.1.1. However, in this case 
no new investment is required, only imports of regasified LNG through the existing routes, at a 
price  higher  than  the  existing  market  price,  for  security  of  supply  purposes.  The  only  costs 
examined  concern  the  premium  paid  to  import  LNG  to  the  market,  whereas  the  benefit  is  the 
enhancement of security of supply. 

Figure A. 78: Assessment of costs and benefits   

The economic analysis was carried out for a 20-year period, assuming commencement of imports 
of regasified LNG in 2020. As in the case of Section A4.1, a social discount rate of 4% has been 
applied in the calculations. 

It is noted that the analysis carried out is high-level, based on assumptions on gas/LNG supply 
prices and market evolution, without examining dynamic supply-demand curves. The results of 
this analysis can be used to draw preliminary conclusions, whereas for a more detailed view of 

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the LNG market development option’s economic performance, modelling of the markets evolution 
is required. 

A4.2.2. Application in Eastern Partner countries 
Economic analysis was conducted only for the case of Moldova, for which supplies of regasified 
LNG is not viable, but could have impact on the country’s security of supply. 

The benefit for enhancing security of supply is assessed by examining a disruption of Russian 
supplies to Moldova. 

Regasified LNG can be supplied from the neighbouring terminals of Świnoujście, Klaipeda and 
the  planned  terminal  in  Krk,  and  through  the  Ukrainian  system.  Additional  supplies  from 
Revythoussa could not reach the market, in case of a supply disruption, as the interconnection 
point with Romania would already be used as much as possible. 

Since the transportation costs from the terminals up to Moldova do not vary considerably (Section 
A2.1.7), and the economic analysis would lead to similar results, we examine only the case of 
Klaipeda.      

A4.2.3. Calculation of demand curtailment in case of disruption 
The daily peak demand and curtailed demand for Moldova is the same with the one estimated in 
Section  A4.1.3  (Figure  A.  69).  The  gas  demand  curtailment  used  to  assess  the  LNG  option’s 
impact for a 2-week disruption is presented in Table A. 99. 

Table A. 99: Curtailed demand in Moldova for a 2-week period for 2020 – 2039 

Daily demand curtailment (mcm/d) 
2-week demand curtailment (mcm) 

2020 
2.1 
28.8 

2024 
2.5 
35.0 

2029 
3.1 
42.9 

2034 
3.2 
44.4 

2039 
3.2 
44.4 

A4.2.4. Monetization of increase of the cost of gas supplies 
The LNG import price is assumed to be the current level of average price at the Klaipeda terminal 
(200 EUR/1000 m3)203. The gas supply price in Moldova is set at the regulated price set by ANRE, 
for entry into the gas transmission system (151.5 EUR/1000 m3)204.  

The transportation costs of regasified LNG up to the Moldovan borders are calculated using the 
tariffs presented in  

203 Source: DG Energy, “Gas Market Report Q2 2019” 
204 Source: Moldovan National Agency for Energy Regulation Decision No 88/2018 

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Table A. 13. It is assumed that the same capacity booking profile as the one presented in Section 
A2.1.4, resulting in a cross-border transportation cost of 45.4 EUR/1000 m3, and a cost of LNG 
terminal use and entry to the Lithuanian transmission system of 17.0 EUR/1000 m3 (Table A. 25). 

With  the  assumed  import  price  of  LNG  and  transportation  costs,  LNG  at  the  Moldovan  market 
would be 111.14 EUR/1000 m3 more expensive. The annual premium to be paid in the market to 
have LNG for security of supply is presented in Table A. 100. 

Table A. 100: Gas price increase in Moldova for current import price (supplies for security of supply) 

Security of supply needs (2-week 
demand curtailment) (mcm) 
Gas price increase (mil. EUR) 

2020 

28.8 

3.2 

2024 

35.0 

3.9 

2029 

42.9 

4.8 

2034 

44.4 

4.9 

2039 

44.4 

4.9 

A4.2.5. Monetization of security of supply benefits 
The approach to determine the monetised benefit of addressing demand curtailment for Moldova 
is the same with that presented in Section A4.1.6. The calculation is presented in Table A. 101.  

Table A. 101: Security of supply benefit for supplies of regasified LNG to Moldova 

Security of supply needs in Moldova 
(2-week demand curtailment) (mcm) 
VoLL in Moldova (EUR/1000 m3) 
Probability of disruption 
SoS benefit for Moldova (mil. EUR) 

2020 

28.8 

2024 

35.0 

4.5 

5.4 

2029 

42.9 

3,096 
5% 
6.6 

2034 

44.4 

2039 

44.4 

6.9 

6.9 

A4.2.6. Results of analysis 
Figure A. 79 presents the evolution of economic costs and benefits of the LNG option of supplying 
regasified LNG from neighbouring terminals to Moldova. 

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Figure A. 79: Evolution of economic costs / benefits for supply of regasified LNG from Klaipeda to 
Moldova 

Table A. 102 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table  A.  102:  Present  value  of  economic  costs  and  benefits  for  supply  of  regasified  LNG  from 
Klaipeda to Moldova 

Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-61.1 
85.3 
24.2 

Table A. 103 presents the economic indicators for the examined LNG option. 

Table A. 103: Economic indicators for supply of regasified LNG from Klaipeda to Moldova 

ENPV (Mil. EUR) 
ERR 
B/C Ratio 

Indicator 
24.2 
N/A 
1.4 

A4.3. Economic  analysis  for  in  case  of  LNG  supplied  from 
liquefaction terminal in Black Sea 
A4.3.1. Analysis approach 
The  aim  of  the  economic  (cost-benefit)  analysis  to  assess  whether  the  economic  costs  for 
developing  and  operating  a  liquefaction  and  export  terminal  in  Georgia,  together  with  an  in-
country LNG receiving terminal in Ukraine are outweighed by its potential benefits to the economy 
and society.  

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The approach followed, and the examined costs and benefits are the same as in Section A4.1. In 
this case, however, the LNG supply costs also include the costs for liquefaction at the Georgian 
terminal and transportation with an LNG vessel to the Ukrainian terminal. 

A4.3.2. Application in Eastern Partner countries 
An economic analysis was conducted for the development of a liquefaction and export terminal in 
Georgia, together with a receiving terminal in Ukraine that allows supply of regasified LNG to the 
Ukrainian and Moldovan markets.  

The netback analysis for this option shows that in all the examined scenarios of Ukrainian import 
price and utilization, the estimated maximum competitive prices at the liquefaction terminal are 
below  the  import  prices  of  Azeri gas  currently  applied  in  the  Georgian  market,  200  EUR/1000 
m3205. The economic analysis was performed for the case having the highest netback price (winter 
average price, 257 EUR/1000 m3), examining two scenarios of Caspian gas export prices (current 
level of Azeri gas supply to Georgia and low export price). Sensitivity analysis on the investment 
costs of the liquefaction is also applied (Section A2.3.6). A matrix of scenarios/sensitivities and 
corresponding prices is presented in Table A. 104. 

Table A. 104: Price scenarios and sensitivities examined 

Price scenario 

Item 

Current Azeri supply 
price to Georgia 

Low export price of 
Caspian gas 

Export price of Caspian gas (EUR/1000 m3) 
Exit from Georgian system 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
LNG Price at Ukrainian terminal (EUR/1000 m3) 
Export price of Caspian gas (EUR/1000 m3) 
Exit from Georgian system 
LNG transportation cost (EUR/1000 m3) 
Liquefaction service charge (EUR/1000 m3) 
LNG Price at Ukrainian terminal (EUR/1000 m3) 

60% 

100% 

Cost of liquefaction 
terminal 
80% 
200 
6.1 
5.5 
79.8 
93.5 
109.6 
321.2  305.1  291.4 
150 
6.1 
5.5 
109.6 
79.8 
93.5 
271.2  255.1  241.4 

For the scenarios that price of LNG arriving at the Ukrainian terminal is higher than the winter 
average  price  in  Ukraine,  the  terminal  will  be  utilized  only  for  security  of  supply  purposes  in 
Ukraine  and  Moldova,  to  cover  potential  demand  curtailment  in  case  of  disruption  in  Russian 
transit that affects the capacity to import gas. The volumes used for security of supply correspond 
to the annual potential curtailed demand estimated in Section A4.1.3. 

For  the  scenarios  that  price  of  LNG  arriving  at  the  Ukrainian  terminal  is  lower  than  the  winter 
average price in Ukraine, terminal utilization of 50% is examined. 

205 Source: Department of Strategic Planning and Projects of GOGC 

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A4.3.3. Definition of investment and operational costs 
The CAPEX and OPEX values defined in Section A4.1.4 are applied. Costs for the liquefaction 
terminal and transportation are included in the price of LNG at the Ukrainian terminal (examined 
as part of the impact on energy costs). 

A4.3.4. Monetization of impact on the costs of gas supplies 
The approach described in Section A4.1.5 is followed. In the scenarios that the LNG supply price 
at Ukraine are higher than that of piped gas, the premium for the import of LNG for security of 
supply  is  estimated  (Table  A.  105).  In  the  scenarios  that  the  LNG  supply  price  at  Ukraine  are 
lower than that of piped gas, the cost saving is estimated (Table A. 106). 

Table A. 105: Annual gas price increase in Ukraine in case LNG is used for security of supply 

Security of supply needs in Ukraine (2-week 
demand curtailment) (mcm) 
Security of supply needs in Moldova (2-week 
demand curtailment) (mcm) 
Gas price increase (mil. EUR) 

1 

- 

Year206 
10 

5 

15 

20 

20.5 

46.2 

46.2 

46.2 

33.5 

39.7 

44.4 

44.4 

44.4 

Current Azeri price 
scenario 

Low export price of 
Caspian gas scenario 

321.2 EUR/1000 m3 
305.1 EUR/1000 m3 
291.4 EUR/1000 m3 

271.2 EUR/1000 m3 

2.1 
1.6 
1.2 

0.5 

3.9 
2.9 
2.1 

0.9 

5.8 
4.4 
3.1 

1.3 

5.8 
4.4 
3.1 

1.3 

5.8 
4.4 
3.1 

1.3 

Table A. 106: Annual gas price decrease in Ukraine for 50% utilization rate 

Annual LNG volumes (mcm) 
Gas price decrease (mil. EUR) 
Low export price of Caspian gas 
scenario 

255.1 EUR/1000 m3 
241.4 EUR/1000 m3 
A4.3.5. Monetization of security of supply benefits 
The monetized benefits for security of supply used are those presented in Table A. 94. 

4.7 
39.0 

50% 
2,500 

A4.3.6. Calculation of remaining benefits (residual value) 
The approach described in Section A4.1.7 is followed. 

A4.3.7. Results of analysis 
Table A. 107 presents the present values of the calculated economic costs and benefits for the 
development  of  a  liquefaction  export  terminal  in  Georgia,  together  with  a  receiving  terminal  in 
Ukraine. 

206 This LNG option can be developed in the medium term, in case additional gas from the Caspian region becomes 
available. It is assumed that the same demand curtailment trend, as the one estimated in Section A4.1.3 will be followed. 
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Table A. 107: Present value of economic costs and benefits for supply of Ukrainian LNG terminal 
from Georgian liquefaction terminal, per examined scenario 

Investment cost sensitivity 
CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Residual value (Mil. EUR) 
Net benefits (Mil. EUR) 

Current Azeri price 
80% 
-594.7 
-46.3 
123.5 
-21.0 
-538.4 

60% 
-593.6 
-33.1 
123.5 
-16.5 
-519.6 

100% 
-595.9 
-61.7 
123.5 
-26.3 
-560.4 

Low export price of Caspian gas 
80% 
-677.7 
59.7 
123.5 
-12.5 
-506.9 

100% 
-592.0 
-13.7 
123.5 
-9.8 
-491.9 

60% 
-672.0 
490.0 
123.5 
106.3 
47.9 

Table  A.  108  presents  the  economic  indicators  for  the  liquefaction  export  terminal  in  Georgia, 
together with a receiving terminal in Ukraine. 

Table A. 108: Economic indicators for supply of Ukrainian LNG terminal from Georgian liquefaction 
terminal, per examined scenario 

Investment cost sensitivity 
ENPV (Mil. EUR) 
ERR 
B/C Ratio 

Current Azeri price 
80% 
-538.4 
N/A 
0.09 

60% 
-519.6 
N/A 
0.12 

100% 
-560.4 
N/A 
0.06 

Low export price of Caspian gas 
80% 
-506.9 
N/A 
0.25 

100% 
-491.9 
N/A 
0.17 

60% 
44.9 
4.9% 
1.07 

Figure A. 80 and Figure A. 81 below present the evolution of economic costs and benefits of the 
examined LNG option, for the case of low Caspian export price, and sensitivities of liquefaction 
terminal investment costs. 

Figure  A.  80:  Evolution  of  economic  costs  /  benefits  for  supply  of  Ukrainian  LNG  terminal  from 
Georgian liquefaction terminal, for low Caspian export price, 80% investment cost  

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Figure  A.  81:  Evolution  of  economic  costs  /  benefits  for  supply  of  Ukrainian  LNG  terminal  from 
Georgian liquefaction terminal, for low Caspian export price, 60% investment cost  

A4.4. Quantitative  indicators  for  gas-to-gas  competition  LNG 
market development options’ assessment 
A4.4.1. Indicators applied 
The economic indicators calculated for the LNG market development options under the gas-to-
gas competition are supplemented by the assessment of quantitative indicators that allow further 
analysis of the options’ impact to the market. 

The indicators applied are mainly capacity-based, as the high-level analysis performed under this 
Study does not include market simulations, and thus modelling-based indicators cannot be used.  
The quantitative indicators examined include: 

  N-1  indicator:  The  indicator  examines  whether  peak  demand  in  the  market  can  be 

satisfied in case its single largest infrastructure is disrupted. 

 

Import  route  diversification:  The  indicator  examines  the  extent  to  which  there  is 
potential for the market to diversify its routes of supply and associated counterparts. 

  Demand  curtailment:  The  indicator  examines  the  extent  to  which  the  market  is 

impacted by a disruption in external supplies. 

The  impact  of  the  LNG  option  is  assessed  by  examining  the  indicators  with  and  without  the 
development of the option. The analysis was conducted for 2025. 

A4.4.2. N-1 Indicator 
The calculation of the N-1 indicator is based on the N-1 formula included in the EC Security of 
Gas Supply Regulation (EU) 2017/1938: 

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𝑁 − 1 =

𝐸𝑃 + 𝑃 + 𝑆 + 𝐿𝑁𝐺 − 𝐼
𝐷𝑚𝑎𝑥

∗ 100 

where: 

  EP: Aggregate firm technical capacity of all cross-border entry points (mcm/d); 

  P: Maximum national production capability (mcm/d); 

  S:  Aggregate  maximum  technical  daily  withdrawal  capacity  (mcm/d)  of  all  storage 

facilities; 

  LNG: Aggregate LNG regasification capacity (mcm/d) of all LNG terminals; 

 

I: Firm technical capacity of the single largest infrastructure (mcm/d); 

  Dmax: peak daily demand in the market (mcm/d).  

To meet the Regulation (EU) 2017/1938 requirements, the N-1 indicator must exceed 100%. 

As  this  indicator  is  capacity-based,  it  is  relevant  for  Georgia  and  Ukraine,  in  which  the  entry 
capacities will change with the development of LNG terminals. 

Georgia 

The calculation of the N-1 indicator for the Georgian market, with and without the development of 
an LNG terminal with send-out capacity of 1 bcm/yr (2.75 mcm/d) is presented in Table A. 109. 
Disruption of the Azeri-Georgia Pipeline, that has the largest capacity, is examined. 

Table A. 109: Calculation of N-1 indicator for Georgia 

Entry Points (EP) (mcm/d)207 

W/o terminal  With terminal 

17.9 

17.9 

North-South Pipeline (mcm/d) 
SCP (mcm/d) 
Azeri-Georgia Pipeline (mcm/d) 

4.5 
5.4 
8 

4.5 
5.4 
8 

Production (P) (mcm/d) 
USG (S) (mcm/d)208 
LNG (mcm/d) 
Largest Infrastructure (I) (mcm/d) 
Peak daily demand in 2025 (Dmax) (mcm/d) 
N-1 indicator 
LNG terminal impact (percentage points) 
LNG terminal impact (% change) 

~0 
N/A 
N/A 
8 
16.1 
61.5% 

~0 
N/A 
2.75 
8 
16.1 
78.5% 

17.0 
28% 

Ukraine 

The calculation of the N-1 indicator for the Ukrainian market, with and without the development of 
an FSRU with send-out capacity of 5 bcm/yr (13.7 mcm/d) is presented in Table A. 110.  

207 Source: Department of Strategic Planning and Projects of GOGC 
208 The planned UGS, not included in the calculations as it has not received an FID yet, will increase the N-1 indicator. 
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For peak demand and production, the forecasts included in the UGS Development Plan 2020 – 
2029 are used as a basis. For the interconnection points, only firm entry capacity is included in 
the calculations. The UGS withdrawal capacity used is not the maximum design withdrawal rate 
but takes into consideration the limitations discussed in Section A4.1.3. Disruption of the Bilche-
Volytsia  UGS,  that  has  the  largest  entry  capacity  to  the  Ukrainian  transmission  system,  is 
examined. 

Table A. 110: Calculation of N-1 indicator for Ukraine 

Entry Points (EP) (mcm/d)209 

W/o terminal  With terminal 

27.0 

27.0 

Budince (Slovakia) (mcm/d) 
Beregdaroc (Hungary) (mcm/d) 
Hermanovice (Poland) (mcm/d) 

27.0 
0 
0 

27.0 
0 
0 

Production in 2025 (P) (mcm/d) 
USG (S) (mcm/d) 
LNG (mcm/d) 
Largest Infrastructure (I) (mcm/d) 
Peak daily demand in 2025 (Dmax) (mcm/d) 
N-1 indicator 
LNG terminal impact (percentage points) 
LNG terminal impact (% change) 

64.9 
150.0 
N/A 
-60 
186.9 
97.3% 

64.9 
150.0 
13.7 
-60 
186.9 
104.7% 

7.3 
8% 

A4.4.3. Import Route Diversification 
The Import Route Diversification (IRD) indicator is calculated using the Herfindahl - Hirschman 
Index (HHI), to assess the share of each gas import point: 

𝑛

𝐼𝑅𝐷 = ∑(
𝑖=1

𝐸𝐶𝑖
∑ 𝐸𝐶𝑛

∗ 100)2

where: 

  EC:  Capacity  of  each  entry  point  to  the  market  (mcm/d),  including  interconnection 
points  with  neighbouring  markets  and  LNG  terminals.  All  interconnection  points 
between two markets are aggregated, regardless of their geographical position . 

  n: Total number of entry points. 

The  lower  the  value  of  IRD,  the  higher  is  the  market’s  potential  to  diversify  its  routes  and 
counterparts. The maximum value is 10,000, corresponding to a market with a single import point. 

As  this  indicator  is  capacity-based,  it  is  relevant  for  Georgia  and  Ukraine,  in  which  the  entry 
capacities will change with the development of LNG terminals. 

Georgia 

209 Source: Input from UTG 

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The calculation of the IRD indicator for the Georgian market, with and without the development of 
an LNG terminal with send-out capacity of 1 bcm/yr (2.74 mcm/d) is presented in Table A. 111. 
The entry points from SCP and the Azeri – Georgia Pipeline are examined jointly as they concern 
gas of the same source. 

Table A. 111: Calculation of IRD indicator for Georgia 

North-South Pipeline 
Azeri entries 
LNG terminal 
Total 
LNG terminal impact 
LNG terminal impact (% change) 

Ukraine 

HHI w/o 
terminal 
632 
5,604 
N/A 
6,236 

HHI with 
terminal 
475 
4,215 
176 
4,867 

1,370 
22% 

The calculation of the IRD indicator for the Ukrainian market, with and without the development 
of an FSRU with send-out capacity of 5 bcm/yr (13.7 mcm/d) is presented in Table A. 112. Both 
firm  and  interruptible  capacity  is  included  in  the  analysis,  given  that  under  normal  market 
operation supplies from all routes arrive to Ukraine.  

Table A. 112: Calculation of IRD indicator for Ukraine 

Budince (Slovakia) 
Beregdaroc (Hungary) 
Hermanovice (Poland) 
Orlovka (Romania) 
LNG terminal 
Total 
LNG terminal impact 
LNG terminal impact (% change) 

HHI w/o 
terminal 
3,399 
716 
77 
38 
N/A 
4,229 

HHI with 
terminal 
2,408 
507 
55 
27 
250 
3,247 

982 
23% 

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A4.4.4. Demand Curtailment 
The demand curtailment is examined using a Disruption Rate (DR) indicator: 

𝐷𝑅 =

𝐷𝐷
𝐷𝑚𝑎𝑥

Where: 

  DD: Curtailed demand on peak day (mcm/d); 

  Dmax: peak daily demand in the market (mcm/d).  

This  indicator  is  estimated  for  Georgia  with  disruption  of  Azeri  gas  supplies,  Ukraine  with 
disruption of Russian gas transit and for Moldova with disruption of Russian gas supplies. The 
curtailed demand for each country has been calculated in Section A4.1.3. 

Georgia 

The calculation of the DR indicator for the Georgian market, with and without the development of 
an LNG terminal with send-out capacity of 1 bcm/yr (2.74 mcm/d) is presented in Table A. 113. 

Table A. 113: Calculation of DR indicator for Georgia 

W/o terminal  With terminal 

Peak daily demand in 2025 (mcm/d) 
Curtailed demand in 2025 (mcm/d) in case 
of Azeri gas disruption 
DR 
LNG terminal impact (percentage points) 
LNG terminal impact (% change) 

16.1 

11.6 

72% 

16.1 

8.9 

55% 

17 
24% 

Ukraine 

The calculation of the DR indicator for the Ukrainian market, with and without the development of 
an LNG terminal with send-out capacity of 5 bcm/yr (13.7 mcm/d) is presented in Table A. 114. 

Table A. 114: Calculation of DR indicator for Ukraine 

Peak daily demand in 2025 (mcm/d) 
Curtailed demand in 2025 (mcm/d) in case 
of Russian transit disruption 
DR 
LNG terminal impact (percentage points) 
LNG terminal impact (% change) 

W/o terminal  With terminal 

186.9 

186.9 

0 

0 

0 

0 

- 
- 

Moldova 

The calculation of the DR indicator for the Moldovan market, with and without the development of 
an LNG terminal in Ukraine with send-out capacity of 5 bcm/yr (13.7 mcm/d) is presented in Table 
A. 115.  

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Table A. 115: Calculation of DR indicator for Moldova 

W/o terminal  With terminal 

Peak daily demand in 2025 (mcm/d) 
Curtailed demand in 2025 (mcm/d) in 
case of Russian gas disruption  
DR 
LNG terminal impact (percentage points) 

6.7 

2.5 

37% 

37 

6.7 

0 

0% 

The imports of regasified LNG from neighboring terminals to Moldova, in case of a disruption of 
Russian gas supplies, would have the same impact. 

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Annex 5: Economic Analysis – Gas-to-Other Fuels 
Competition  

A5.1. Economic analysis for LNG as fuel for long-haul trucks 
A5.1.1. Analysis approach 
The aim of the economic (cost-benefit) analysis to assess whether the costs for developing and 
operating the infrastructure necessary for the use of LNG as engine fuel in long-haul trucks (filling 
stations and LNG trucks for the supply of LNG) are outweighed by its potential benefits to the 
economy and society. The economic analysis was carried out for the minimum size of the LNG 
market  in  each  Eastern  Partner  country,  for  which  LNG  is  competitive  to  diesel  (calculated  in 
Section A3.1.10). 

The approach followed is in accordance with the EC CBA Guide for infrastructure investments210. 

The costs and monetized benefits assessed are the following (Figure A. 82): 

  Costs:  

Investment costs for the development of an LNG filling station in the country; 

o 
o  Cost for purchase of LNG trucks to transport LNG to the filling station; 
o  Annual operating costs for the filling station and trucks. 

  Monetized benefits:  

o  Reduction of energy costs for final consumers; 
o  Environmental benefits from reduction of GHGs.  

Figure A. 82: Assessment of costs and benefits 

210 DG Regio (2015) EC CBA Guide for infrastructure investments, available at: 
https://ec.europa.eu/regional_policy/sources/docgener/studies/pdf/cba_guide.pdf  

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The  economic  analysis  was  carried  out  for  a  20-year  period,  assuming  development  of  the 
required infrastructure in 2020 and commencement of LNG supplies in 2021. As in the case of 
Annex 4, a social discount rate of 4% has been applied in the calculations. 

The analysis results in the estimation of the key economic performance indicators; the Economic 
Net Present Value (ENPV), Economic Rate of Return (ERR), and Benefit-to-Cost ratio (B/C).  

A5.1.2. Application in Eastern Partner countries 
An economic analysis was carried out for the Eastern Partner countries for which the required 
minimum  number  of  LNG-fueled  trucks  can  potentially  be  considered  as  attainable.  Armenia, 
Belarus, Georgia and Ukraine were examined (Table A. 116). 

Table A. 116: LNG market examined for each Eastern Partner country 

Number of LNG-fuelled trucks 
Size of LNG market (mcm) 

Armenia 
134 
3.63 

Belarus 
205 
5.56 

Georgia 
62 
1.68 

Ukraine 
60 
1.63 

For each country, the examined source of LNG supply is the following: 

  For Armenia, supply from a potential LNG terminal in Georgia; 

  For Belarus, supply from the Klaipeda LNG reloading station; 

  For Georgia, supply from a potential in-country receiving terminal; 

  For Ukraine, supply from the Świnoujście LNG terminal. 

It is noted that the minimum market size used for the analysis of each country is defined according 
to  the  characteristics  of  the  country,  and  not  using  uniform  assumptions  across  all  Eastern 
Partners.  For  this  reason,  the  results  of  the  economic  analysis  provide  an  indication  of  the 
economic impact of the LNG option on the specific country but are not comparable on a regional 
level. 

A5.1.3. Definition of investment and operational costs 
The CAPEX and OPEX values used for the filling station and LNG trucks are the same with those 
used for the netback analysis, presented in Table A. 51 and Table A. 52 respectively. 

As the life cycle of an LNG filling station is assumed to be 10 years, and that of an LNG truck 8 
years,  additional  investments  need  to  be  taken  into  consideration  in  the  20-year  economic 
analysis. It is assumed that, to continue the supply of LNG, a new investment for the filling station 
(equal to the initial investment) will be carried out in the 10th year, and new LNG trucks will be 
procured in the 8th and 16th year.  

A5.1.4. Monetization of reduction of energy costs 
The price differential between LNG and diesel will result in a reduction in the consumers’ energy 
costs. The competing fuel price assessed at the filling station includes the equivalent LNG price 
of diesel, net of the fuel switching costs (calculated in Section A3.1.3 and Section A3.1.4).  The 
LNG import price and truck loading costs assumed for each country depends on its supply source 
(Table A. 117).  

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Table A. 117: LNG price differential estimated for each Eastern Partner country 

LNG equivalent price (EUR/1000 m3) 
Fuel switching cost (EUR/1000 m3) 
Competing price “at the pump" (EUR/1000 m3) 
LNG import price (EUR/1000 m3) 
Truck loading cost (EUR/1000 m3) 
Unit price reduction (EUR/1000 m3) 

Armenia 
702.5 

Belarus 
647.6 

Georgia 
779.3 

Ukraine 
834.2 

406.5 
220 
46.8 
139.7 

296.0 

351.6 
200 
46.8 
104.8 

483.3 
220 
46.8 
216.5 

538.2 
200 
10.4 
327.8 

For each market, it is assumed that there will be a gradual increase of the number of LNG-fuelled 
trucks, corresponding to 25% of the total number in the 1st year, 50% in the 2nd year and reaching 
100% from the 3rd year onwards. Table A. 118 presents the annual energy cost saving for each 
country.  

Table A. 118: Annual energy cost saving for each Partner Country 

Unit price reduction (EUR/1000 m3) 
LNG sales (mcm) 
Annual energy cost saving (mil. EUR) 

Armenia 
139.7 
3.63 
0.51 

Belarus 
104.8 
5.56 
0.58 

Georgia 
216.5 
1.68 
0.36 

Ukraine 
327.8 
1.63 
0.53 

As the analysis was performed on the basis of the minimum market size required for the LNG 
option to be economically viable, the price differential of LNG and diesel will be sufficient to cover 
costs for development and operation of the filling station, and the transportation of LNG with trucks 
from the terminal to the filling station. 

A5.1.5. Monetization of environmental benefits 
The monetization of the environmental benefits for switching from the current use of diesel to LNG 
is based on estimating the difference in GHG emissions for the two fuels, and shadow prices of 
GHG, which reflect the future cost of emissions. 

The impact of the competing fuels on GHG emissions depends on factors such as the type and 
age  of the trucks (e.g.  a fleet  of  old trucks  with Euro-4 engines  would have a  different  carbon 
footprint than a renewed fleet Euro-6 engines), and their service modality (distance travelled in 
urban  and  rural  areas/motorways).  For  example,  a  recent  TNO  study 211 concluded  that,  for 
specific engines and routes, LNG CO2 and CH4 tank-to-wheel emissions are lower than those of 
diesel, whereas LNG NOx emissions, specifically in urban areas, are higher while in motorways 
they are equal or lower than diesel. 

For  the  purpose  of  the  high-level  analysis  performed  in  this  Study,  we  apply  a  benchmark 
aggregate value of GHG emissions for each fuel212. To ascertain the actual impact of switching to 
LNG  in  each  country,  the  conditions  in  the  country’s  transport  sector  (type  and  age  of  truck 
engines, service modalities, regulatory limitations) would have to be further analysed.      

211 TNO, Emissions testing of a Euro VI LNG-diesel dual fuel truck in the Netherlands, April 2019 
212 Source: I. Smajla et al. (Energies Journal),” Fuel Switch to LNG in Heavy Truck Traffic”, 2019 

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To estimate the economic benefit of emissions reduction, we apply the shadow price of CO2 used 
by ENTSOs in the TYNDP 2018 scenarios213. The scenario path examined is the 2020-Expected 
Progress,  2025  Coal-Before-Gas,  2030-2040  Sustainable-Transition,  which  is  the  most 
conservative  path  of  CO2  prices’  increase.  The  CO2  prices  for  the  intermediary  years  are 
calculated by applying linear interpolation (Figure A. 83). 

Figure A. 83: Assumed growth of CO2 prices 

Source: ENTSOs TYNDP Scenario Report, Scenarios Fuel & CO2 Prices 

As  an  example of the  estimation  of  annual monetized  benefit from GHG  emissions’  reduction, 
Table A. 119 presents the calculations for 2025, for each country.  

Table A. 119: Annual energy cost saving for each Partner Country for 2025 

GHG emission for diesel (kg CO2eq/km) 
GHG emission for LNG (kg CO2eq/km) 
Total emissions for diesel (kg CO2eq/km) 
Total emissions for LNG (kg CO2eq/km) 
CO2 price (EUR/ton CO2eq) 
Annual energy cost saving (mil. EUR) 

Armenia 

Belarus 

Georgia 

Ukraine 

2.83212 
2.57212 

34,504 
31,365 

52,786 
47,984 

15,965 
14,512 

15,450 
14,044 

0.08 

0.12 

0.04 

0.04 

25.7 

A5.1.6. Results of analysis 
Armenia 

Figure A. 84 presents the evolution of economic costs and benefits of the use of LNG as fuel for 
long-haul trucks in Armenia. 

213 ENTSOs TYNDP Scenario Report, Scenarios Fuel & CO2 Prices 

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Figure A. 84: Evolution of economic costs / benefits for LNG as fuel for long-haul trucks in Armenia 

Table A. 120 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table A. 120: Present value of economic costs and benefits for LNG as fuel for long-haul trucks in 
Armenia 

CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-5.7 
6.3 
1.3 
1.9 

Table A. 121 presents the economic indicators for the examined LNG option. 

Table A. 121: Economic indicators for LNG as fuel for long-haul trucks in Armenia 

ENPV (Mil. EUR) 
B/C Ratio 

Indicator 
1.89 
1.33 

Belarus 

Figure A. 85 presents the evolution of economic costs and benefits of the use of LNG as fuel for 
long-haul trucks in Belarus. 

Figure A. 85: Evolution of economic costs / benefits for LNG as fuel for long-haul trucks in Belarus 

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Table A. 122 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table A. 122: Present value of economic costs and benefits for LNG as fuel for long-haul trucks in 
Belarus 

CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-6.6 
7.2 
1.9 
2.6 

Table A. 123 presents the economic indicators for the examined LNG option. 

Table A. 123: Economic indicators for LNG as fuel for long-haul trucks in Belarus 

ENPV (Mil. EUR) 
B/C Ratio 

Indicator 
2.56 
1.39 

Georgia 

Figure A. 86 presents the evolution of economic costs and benefits of the use of LNG as fuel for 
long-haul trucks in Georgia. 

Figure A. 86: Evolution of economic costs / benefits for LNG as fuel for long-haul trucks in Georgia 

Table A. 124 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table A. 124: Present value of economic costs and benefits for LNG as fuel for long-haul trucks in 
Georgia 

CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-3.9 
4.5 
0.6 
1.2 

Table A. 125 presents the economic indicators for the examined LNG option. 

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Table A. 125: Economic indicators for LNG as fuel for long-haul trucks in Georgia 

ENPV (Mil. EUR) 
B/C Ratio 

Indicator 
1.23 
1.32 

Ukraine 

Figure A. 87 presents the evolution of economic costs and benefits of the use of LNG as fuel for 
long-haul trucks in Ukraine. 

Figure A. 87: Evolution of economic costs / benefits for LNG as fuel for long-haul trucks in Ukraine 

Table A. 126 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table A. 126: Present value of economic costs and benefits for LNG as fuel for long-haul trucks in 
Ukraine 

CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-6.0 
6.6 
0.6 
1.2 

Table A. 127 presents the economic indicators for the examined LNG option. 

Table A. 127: Economic indicators for LNG as fuel for long-haul trucks in Ukraine 

ENPV (Mil. EUR) 
B/C Ratio 

Indicator 
1.16 
1.19 

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A5.2. Economic analysis for LNG supply to off-grid consumers 
A5.2.1. Analysis approach 
The aim of the economic (cost-benefit) analysis to assess whether the costs for supplying an off-
grid consumer (investment and operating expenses for a small-scale regasification facility at the 
consumer,  and  for  using  LNG  trucks  to  supply  the  facility)  are  outweighed  by  its  potential 
economic benefits for cost reduction and reduction of GHG emissions.  

The overall approach is the same with the one described in Section A4.1.1.  In this case, the costs 
and monetized benefits assessed are the following (Figure A. 88): 

  Costs:  

o 

Investment  costs  for  the  development  of  a  small-scale  LNG  storage  and 
regasification facility at the consumer’s site; 

o  Cost for purchase of LNG trucks to transport LNG to the regasification facility; 
o  Annual operating costs for the facility and trucks. 

  Monetized benefits:  

o  Reduction of energy costs for the examined final consumer; 
o  Environmental benefits from reduction of GHGs.  

Figure A. 88: Assessment of costs and benefits 

The  economic  analysis  was  carried  out  for  a  20-year  period,  assuming  development  of  the 
required infrastructure in 2020 and commencement of LNG supplies in 2021. As in the case of 
Annex 4, a social discount rate of 4% has been applied in the calculations. 

The analysis results in the estimation of the key economic performance indicators; the Economic 
Net Present Value (ENPV), Economic Rate of Return (ERR), and Benefit-to-Cost ratio (B/C). 

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A5.2.2. Application in Eastern Partner countries 
Economic analysis was carried out for the case study of an off-grid agriculture site in Ukraine that 
is examined in Section A3.3 with annual gas demand of 5.2 mcm. The supply from the Świnoujście 
LNG terminal is analysed. 

A5.2.3. Definition of investment and operational expenses 
The CAPEX and OPEX values used for the regasification and LNG trucks are the same with those 
used for the netback analysis, presented in Table A. 74 and Table A. 75 respectively. 

As the life cycle of a regasification facility is assumed to be 10 years, and that of an LNG truck 8 
years,  additional  investments  need  to  be  taken  into  consideration  in  the  20-year  economic 
analysis. It is assumed that, to continue the supply of LNG, a new investment for the regasification 
facility (equal to the initial investment) will be carried out in the 10th year, and new LNG trucks will 
be procured in the 8th and 16th year. 

A5.2.4. Monetization of reduction of energy costs  
The price differential between LNG and LPG will result in a reduction in the energy costs of the 
agriculture site. The competing fuel price assessed at the end consumer includes the equivalent 
LNG price of LPG (calculated in Section A3.3.3).  The estimation of the price differential, for supply 
of LNG from the Świnoujście LNG terminal is presented in Table A. 128. 

Table A. 128: LNG price differential for the supply of LNG to the agriculture site 

LNG equivalent price (EUR/1000 m3) 
LNG import price (EUR/1000 m3) 
Truck loading cost (EUR/1000 m3) 
Unit price reduction (EUR/1000 m3) 

Ukraine 
508.5 
200 
10.4 
298.1 

Table A. 129 presents the annual energy cost saving for the end consumer. As the consumption 
of gas is assumed to remain constant, the savings are the same for all years of the analysis. 

Table A. 129: Annual energy cost saving for the supply of LNG to the agriculture site 

Unit price reduction (EUR/1000 m3) 
Gas consumption (mcm) 
Annual energy cost saving (mil. EUR) 

2021 
298.1 
5.2 
1.55 

2025 
298.1 
5.2 
1.55 

2030 
298.1 
5.2 
1.55 

2035 
298.1 
5.2 
1.55 

2040 
298.1 
5.2 
1.55 

A5.2.5. Monetization of environmental benefits 
The  monetization  of  the  environmental  benefits  for  the  agriculture  site  switching  from  LPG  to 
natural gas is based on estimating the difference in GHG emissions for the two fuels, and shadow 
prices of GHG, which reflect the future cost of emissions. 

The  values  applied  for  GHG  emissions  used  for  natural  gas  and  LPG  are  those  applied  by 
ENTSOG in the TYNDP 2017. The CO2 prices used are those define in Section A5.1.5. 

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Table A. 130: Annual energy cost saving for the supply of LNG to the agriculture site 

GHG emission for diesel (kg CO2eq/kWh) 
GHG emission for natural gas (kg CO2eq/kWh) 
Total emissions for diesel (kg CO2eq/km) 
Total emissions for LNG (kg CO2eq/km) 
CO2 price (EUR/ton CO2eq) 
Annual energy cost saving (mil. EUR) 

2021 

2025 

13,235 
1,508 
19.5 
0.03 

13,235 
11,508 
21.1 
0.04 

2030 
0.23214 
0.20214 
13,235 
11,508 
25.7 
0.04 

2035 

2040 

13,235 
11,508 
33.3 
0.06 

13,235 
11,508 
45.0 
0.08 

A5.2.6. Results of analysis 
Figure A. 89 presents the evolution of economic costs and benefits of the use of LNG as a means 
to supply gas to off-grid consumers in Ukraine.  

Figure A. 89: Evolution of economic costs / benefits for LNG supply to off-grid consumers in Ukraine 

Table A. 131 presents the present values of the calculated economic costs and benefits for the 
examined LNG option. 

Table A. 131: Present value of economic costs and benefits for LNG supply to off-grid consumers 
in Ukraine 

CAPEX + OPEX (Mil. EUR) 
Impact on gas price (Mil. EUR) 
SoS benefit (Mil. EUR) 
Net benefits (Mil. EUR) 

Present 
Value 
-17.4 
21.0 
0.7 
4.3 

Table A. 132 presents the economic indicators for the examined LNG option. 

Table A. 132: Economic indicators for LNG supply to off-grid consumers in Ukraine 

ENPV (Mil. EUR) 
B/C Ratio 

Indicator 
4.3 
1.25 

214 ENTSOG TYNDP 2017  

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Annex 6: Key LNG infrastructure cost benchmarks 

The Table below summarizes the investment cost benchmarks for LNG infrastructure that have 
been used in the analysis of this Study. 

Item 
On-shore LNG terminal 
FSRU vessel 
LNG truck 
Retrofitting costs for LNG-fueled truck 
LNG filling station 

Small-scale liquefaction facility 

Small scale LNG storage 

Investment cost benchmark 
250 USD/tpa215 
260 mil. EUR/vessel215 
310,000 EUR/truck216  
22,000 EUR/truck217 
528,000 EUR/station218 
7.7 – 12.5 mil. EUR (for capacities ranging from 16 
ton/d to 50 ton/d of LNG production) 219  
800 – 3,000 USD/m3 220 

215 Source: Oxford Institute for Energy Studies, “The Outlook for Floating Storage and Regasification Units”, 2017 
216 Source: Interview with Klaipedos Nafta 
217 Assumption based on reported range of prices from various sources 
218 Source: NGVA Europe, EC 7th Framework Programme, “Cost analysis of LNG refuelling stations”, 2016 
219 Source: World Bank, “Mini / Micro LNG for commercialization of small volumes of associated gas”, 2015 
220 Source: IGU, “2012 – 2015 Triennium Work Report – Small Scale LNG”, 2015 

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Annex 7: Currency / Unit Conversions 

Exchange rates: 

1 USD = 0.91 EUR 

1 BYR = 0.44 EUR 

1 GEL = 0.32 EUR 

1 UAH = 0.034 EUR 

1 AMD = 0.0019 EUR 

1 AZN = 0.52 EUR 

1 PLN = 0.23 EUR 

1 MLD = 0.051 EUR 

1 LEI = 0.21 EUR 

1 BGN = 0.51 EUR 

Gross Calorific Values: 

Polish Transmission System: 11.56 kWh/m3 

Klaipeda LNG terminal: 11.70 kWh/m3 

Bulgarian Transmission System: 11.42 kWh/m3 

Romanian / Moldovan Interconnection: 11.13 kWh/m3 

Romanian / Ukrainian Interconnection: 11.41 kWh/m3 

Croatian Transmission System: 11.33 kWh/m3 

Ukrainian Transmission System: 11.1 kWh/m3 

Moldovan Transmission System: 11.4 kWh/m3 

Hungarian Transmission System: 11.41 kWh/m3 

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