Technical Assistance Consultant’s R eport Project Number: 48030-001 February 2020
Mongolia: S trategy for Northeast Asia Power S ystem Interconnection (Cofinanced by the C limate Change Fund, the People’s R epublic of China R egional Cooperation and Poverty R eduction Fund, and the R epublic of Korea e-Asia and Knowledge Partnership Fund)
Prepared by
E lectricite de France
Paris, France
For the Ministry of E nergy, Mongolia
This consultant’s report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents.
TA 9001-MON: S trategy for Northeast Asia Power S ystem Interconnections
E DF R eferences: C IS T – DCO – PhL – 19 - 145
This consultant’s report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents.
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FOREWORD
The project Team would like to thanks:
. The Ministry of Energy of Mongolia for easing direct discussions with the National Dispatching Center and TRANSCO
. The ADB’s Country Coordinators of Mongolia, Republic of Korea, Japan and Peo-ples Republic of China for their help
Here is a reminder of the place of the Module 6 in the Project organization:
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TABLE OF CONTENTS
EXECUTIVE SUMMARY ................................................................................................................................. 13
1 BENCHMARK OF REGIONAL INTERCONNECTIONS ............................................................... 17
1.1 OBJECTIVES ............................................................................................................................ 17
1.2 AFRICA INTERCONNECTION ................................................................................................. 18
1.2.1 General Description ........................................................................................................... 18
1.2.2 Existing Interconnections ................................................................................................... 18
1.2.3 Main Targets of work ......................................................................................................... 20
1.2.4 Organization and Responsibilities ..................................................................................... 22
1.2.5 Central African Power Pool ............................................................................................... 24
1.2.6 South African Power Pool .................................................................................................. 25
1.2.7 East African Power Pool .................................................................................................... 26
1.2.8 West African Power Pool ................................................................................................... 27
1.2.9 Next Steps ......................................................................................................................... 31
1.2.9.1 Phased Implementation scheme ................................................................................... 31
1.2.9.2 Investment Estimate ...................................................................................................... 34
1.2.10 Conclusions: Lessons Learned For NAPSI ....................................................................... 36
1.3 SOUTH AMERICA: SIEPAC ..................................................................................................... 36
1.3.1 General Description ........................................................................................................... 36
1.3.2 Organization for Regulation and Operation of the SIEPAC Electricity Market .................. 38
1.3.3 Organization for Regulation and Operation of the SIEPAC Electricity Market .................. 39
1.3.4 Power trade and tariff ........................................................................................................ 39
1.3.5 Conclusion: Lessons Learned for NAPSI .......................................................................... 40
1.4 EUROPE .................................................................................................................................... 40
1.4.1 The stages of the European Union construction ............................................................... 40
1.4.2 The Europe Power System Interconnection ...................................................................... 43
1.4.3 The European Regulation .................................................................................................. 47
1.4.4 The European Interconnection .......................................................................................... 47
1.4.5 The European Internal Market Energy Packages ............................................................. 48
1.4.5.1 Description of the 3 Energy Packages .......................................................................... 48
1.4.5.2 The Regulatory Coordination by ACER ......................................................................... 50
1.4.5.3 The TSO’s coordination by ENTSOe ............................................................................. 51
1.4.5.4 The Florence Forum ...................................................................................................... 51
1.4.5.5 The Europe Network Codes .......................................................................................... 51
1.4.5.6 European Stakeholder Committees ............................................................................... 53
1.4.6 The Europe 10-Year Network Development Plan ............................................................. 54
1.4.7 The Trans-European Network TEN-E and Project of Common interest PCI .................... 56
1.4.8 The regimes for Interconnection in Europe ....................................................................... 56
1.4.8.1 The Regulated regime ................................................................................................... 57
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1.4.8.2 The Private regime ........................................................................................................ 58
1.4.8.3 The CAP and FLOOR Regulatory regime ..................................................................... 59
1.4.9 Conclusions: Lessons learned from Europe for NAPSI ..................................................... 61
2 INVESTMENT COST RECOVERY................................................................................................ 62
2.1 OBJECTIVES ............................................................................................................................ 62
2.2 RENEWABLE ENERGY IN MONGOLIA .................................................................................. 62
2.2.1 Introduction on the Mongolian Power System ................................................................... 62
2.2.2 Renewable Energy Projects .............................................................................................. 65
2.2.3 Investment and tariff .......................................................................................................... 67
2.2.4 Further development.......................................................................................................... 72
2.2.4.1 Renewable Energy Policies ........................................................................................... 72
2.2.4.2 Renewable Energy Law Amendment ............................................................................ 74
2.2.5 Recommendations the development of Renewable Energies in Mongolia ....................... 76
2.3 CONVENTIONAL POWER ....................................................................................................... 77
2.3.1 Experience of CHP5 .......................................................................................................... 77
2.3.1.1 Project Development Milestones ................................................................................... 77
2.3.1.2 Project Site .................................................................................................................... 77
2.3.1.3 Project Needs ................................................................................................................ 78
2.3.1.4 CHP-5 Tariff and Increase of CES Tariff ....................................................................... 79
2.3.1.5 Project Structure ............................................................................................................ 79
2.3.1.6 The Consortium disbandment ....................................................................................... 80
2.3.1.7 Requirements to be fulfilled prior to Signing Date ......................................................... 81
2.3.2 Upgrade in Conventional Power Project............................................................................ 82
2.3.2.1 National Energy Policy Mid-term Implementation Program (2018-2023) ...................... 82
2.3.2.2 Policies and Measures for Implementation up to 2030 ................................................. 82
2.3.2.3 Convectional Generation GHG Emission ...................................................................... 83
2.3.3 Recommendations for new Conventional Power in Mongolia ........................................... 84
2.4 INTERCONNECTIONS ............................................................................................................. 84
2.4.1 Notion of Economic Congestion Rent ................................................................................ 84
2.4.2 Notion of interconnection benefit ....................................................................................... 85
2.4.3 Transmission Tariffs .......................................................................................................... 85
2.4.4 Questionable relevance of Transmission Tariffs regarding the cost recovery of
interconnectors .................................................................................................................................. 86
2.4.5 General recommendations for Cost Recovery Methodologies .......................................... 87
2.4.6 Congestion management Methodologies .......................................................................... 88
2.4.7 Recommendations for the organization of the NEA Power Trade .................................... 90
2.4.7.1 Interconnector financing ................................................................................................ 90
2.4.7.2 Interconnector Cost Recovery ....................................................................................... 90
2.4.7.3 Regulation requirements ............................................................................................... 92
2.5 MONGOLIA GRID UPGRADE .................................................................................................. 93
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2.5.1 Objectives .......................................................................................................................... 93
2.5.2 Recommendation option N°1: the new 500kV grid in Mongolia is considered as part of the
NEA interconnection .......................................................................................................................... 94
2.5.2.1 Recommendation option N°2: the new 500kV grid in Mongolia is considered as an
interconnection between Russia and China .................................................................................. 94
3 REGULATION FRAMEWORK AT REGIONAL LEVEL: THE NAPSI AUTHORITY .......................... 95
4 FINANCING THE ENERGY SECTOR IN MONGOLIA.................................................................. 96
4.1 OBJECTIVES ............................................................................................................................ 96
4.2 TYPE OF INVESTMENTS TO BE CONSIDERED ................................................................... 96
4.3 INVESTMENT ENVIRONMENT, INTERNATIONAL FRAMEWORK ....................................... 97
4.4 THE TYPOLOGY OF INVESTORS ........................................................................................... 98
4.4.1 The multilateral and bilateral Financial Institutions ............................................................ 98
4.4.2 The Government financing .............................................................................................. 102
4.4.3 The Private Sector equity investment .............................................................................. 102
4.4.4 The Private Lenders ........................................................................................................ 104
4.4.5 Other sources of funding ................................................................................................. 105
4.5 THE INVESTMENT IN MONGOLIA AS OF TODAY .............................................................. 105
4.5.1 Foreign direct investment is on continuous rise showing good perspective to Mongolia
attractiveness................................................................................................................................... 105
4.5.2 With a target of 30% of renewable energies, renewables offer opportunities for the
Mongolian economy ........................................................................................................................ 106
4.5.3 Conventional Power remains questionable ..................................................................... 107
4.6 APPETITE FOR EQUITY / DEBT INVESTMENT: BOTTOM UP METHOD WITH
QUESTIONNNAIRE ............................................................................................................................ 109
4.7 LESSONS LEARNED FOR NAPSI ........................................................................................ 115
5 GENERAL CONCLUSIONS ........................................................................................................ 117
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LIST OF TABLES
Table 1 : The studied regional interconnections................................................................... 17
Table 2 : African energy and power organization ................................................................. 23
Table 3 : WAPP implementation framework ........................................................................ 28
Table 4 : Parameters of power grid investment estimate of each voltage level ................... 35
Table 5 : History of SIEPAC ................................................................................................ 37
Table 6 : SIEPAC regulation modifications at national and regional levels ........................... 39
Table 7 : Definitions of the different levels of regulation in Europe ....................................... 47
Table 8 : The Network Code family ..................................................................................... 52
Table 9 : TYNDP in numbers ............................................................................................... 55
Table 10 : Comparison between the regulatory coordination
of Europe, Africa and South America ................................................................................... 61
Table 11 : New power sources to be installed by 2020 ........................................................ 66
Table 12 : Mongolia energy policy since 2001 ..................................................................... 73
Table 13 : Mongolia Energy State Policy ............................................................................. 73
Table 14 : Renewable energy projects in Mongolian government plan (2016-2020) ............ 74
Table 15 : Current Feed-in-Tariffs (“FIT”)............................................................................. 74
Table 16 : CHP5 – Requirements to be fulfilled prior to Signing Date .................................. 81
Table 17 : Mongolia energy development 2010-2030 .......................................................... 83
Table 18 : EDC in the Philippines renewable energy sector .............................................. 101
Table 19 : The Markbygden Ett project .............................................................................. 104
Table 20 : Potential investors that are present in Mongolia ................................................ 109
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LIST OF FIGURES
Figure 1 : African Power Pools ............................................................................................ 18
Figure 2 : Africa Transmission Grids .................................................................................... 20
Figure 3 : Main targets for each African Power Pool ............................................................ 21
Figure 4 : Prediction of average cost per kWh of various power sources in Africa ............... 22
Figure 5 : APUA and NEPAD logos ..................................................................................... 23
Figure 6 : CEEAC-ECCAS, CEDEAD-ECOWAS and SADC logos ...................................... 23
Figure 7 : CAPP organizational chart ................................................................................... 25
Figure 8 : SADC organizational chart .................................................................................. 26
Figure 9 : EAPP organizational chart ................................................................................... 27
Figure 10 : ECOWAS organizational chart ........................................................................... 29
Figure 11 : WAPP Phase 1 .................................................................................................. 30
Figure 12 : WAPP Phase 2 .................................................................................................. 30
Figure 13 : WAPP Phase 3 .................................................................................................. 30
Figure 14 : Schematic diagram of African overall power grid pattern in 2030 ....................... 31
Figure 15 : Schematic diagram of African overall power grid pattern in 2040 ....................... 32
Figure 16 : Schematic diagram of African overall power grid pattern in 2050 ....................... 34
Figure 17 : Investment in power interconnection of different regions in Africa
from 2018 to 2050 ............................................................................................................... 36
Figure 18 : Interconnection capacity of SIEPAC .................................................................. 38
Figure 19 : The construction of the European Union ............................................................ 41
Figure 20 : The 5 synchronous zones of Europe power interconnection .............................. 43
Figure 21 : Phase I of Europe power interconnection .......................................................... 44
Figure 22 : Phase III of Europe power interconnection ........................................................ 46
Figure 23 : Map of the Europe power interconnection with NTC in MW ............................... 48
Figure 24 : Map of the latest TYNDP ................................................................................... 55
Figure 25 : The Projects of Common Interest ...................................................................... 56
Figure 26 : New interconnection involving 2 TSO’s B&C can benefit to others A&D ............ 57
Figure 27 : 3 examples of Merchant Transmission Initiative (MTI) ....................................... 59
Figure 28 : Revenues are “capped” at an upper limit ........................................................... 60
Figure 29 : The Energy System of Mongolia ........................................................................ 63
Figure 30 : Installed electricity generating capacity by source ............................................. 63
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Figure 31 : Mongolia existing Supply-Demand..................................................................... 64
Figure 32 : Future power demand in Mongolia .................................................................... 65
Figure 33 : New power sources to be installed by 2020 ....................................................... 66
Figure 34 : Tsetsii Wind farm description ............................................................................. 68
Figure 35 : Tsetsii Wind Farm interest expense ................................................................... 68
Figure 36 : Tsetsii Wind farm development cost .................................................................. 69
Figure 37 : Tsetsii Wind Farm Gearing ................................................................................ 69
Figure 38 : Current Solar, Wind and Hydro licenses in Mongolia ......................................... 71
Figure 39 : Solar power plant license owners ...................................................................... 71
Figure 40 : Wind, Hydro and Biomass power plant license owners ...................................... 71
Figure 41 : CPH5 project site ............................................................................................... 77
Figure 42 : CHP5 Tariff History and Forecast ...................................................................... 79
Figure 43 : CHP5 Project Structure ..................................................................................... 80
Figure 44 : GHG emissions share by sector in 2010 and 2030 ............................................ 83
Figure 45 : Definition of the Economic Congestion Rent ..................................................... 84
Figure 46 : New interconnector that is part of a ring ............................................................ 85
Figure 47 : « Cap and Floor » principle. ............................................................................... 87
Figure 48 : Recommended principle for interconnector cost recovery .................................. 90
Figure 49 : Illustration of the recommended principle for interconnector cost recovery ........ 91
Figure 50 : Recommended Mongolia grid upgrade from Module 5 report ............................ 93
Figure 51 : 4 main types of projects to be financed .............................................................. 96
Figure 52 : Mongolia’s agreement with foreign countries ..................................................... 98
Figure 53 : Foreign Direct Investment in Mongolia ............................................................. 106
Figure 54 : Tessai Wind farm ............................................................................................. 106
Figure 55 : CHP5 ............................................................................................................... 107
Figure 56 : Assessment methodology ................................................................................ 109
Figure 57 : Mongolia risk assessment methodology .......................................................... 112
Figure 58 : Pro and cons analysis for coal in Mongolia ...................................................... 114
Figure 59 : The NAPSI Authority organization ................................................................... 117
Figure 60 : Recommended cost recovery methodology for interconnectors ....................... 118
Figure 61 : Illustration of the recommended interconnector cost recovery methodology .... 118
Figure 62 : Recommended Mongolia’s grid upgrade ......................................................... 119
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PHYSICAL UNITS
cal calorie (1 cal = 4.1868 J)
Gcal Giga calorie
GWh Gigawatt-hour
h hour
km kilometer
km² square kilometer
kW kilo Watt
kWp kilo Watt peak (solar PV)
kWh kilo Watt hour (1 kWh = 3.6 MJ)
MJ Million Joule (= 0,948.10–3 MBtu = 238.8 kcal)
MTOE Million Tonnes of Oil Equivalent
MW Mega Watt
m meter
pu per unit
sqm Square meter
t ton
toe tons of oil equivalent
tcf ton cubic feet
°C degree Celsius
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ABBREVIATIONS AND ACRONYMS
AC Alternative Current
ACER Agency for the Cooperation of Energy Regulators (EU)
ADB Asian Development Bank
AIIB Asian Infrastructure Investment Bank
APUA Association of Power Utilities of Africa
ASEAN Association of Southeast Asian Nations
ATSOI Association of the Transmission System Operators of Ireland
AUES Altai-Uliastai Energy System
BNP Banque Nationale de Paris (Bank)
BOOT Build Own Operate and Transfer
CACM Capacity Allocation and Congestion Management
CAPEX Capital Expenditure
CAPP Central Africa Power Pool
CBA Cost Benefit Analysis
CEEAS Communauté Economique des Etats de l’Afrique Centrale (ECCAS)
CEF Connecting Europe Facility
CEO Chief Executive Officer
CEPRI China Electric Power Research Institute
CES Central Energy System (Mongolia)
CFO Chief Financial Officer
CHP Combined Heat Power
COMELEC CoMité Magrébin de l’électricité
COMESA Common Market for Eastern and Southern Africa
COO Chief Operating Officer
CRIE Comisión Regional del Interconexión Eléctrica (Central America)
CSA Coal Supply Agreement
DC Direct Current
DEG Deutsche Investitions und Entwicklungsgesellschaft (Bank)
DEIA Detailed Environmental Impact Assessment
DT Derechos de Transmisión (Central America)
EAC East African Community
EAEC European Atomic Energy Community
EAPP East Africa Power Pool
EC European Commission
ECCAS Economic Community of Central Africa States
ECOWAS Economic Community of West African States
EDC Energy Development Corporation (The Philippines)
EDC Export Development Canada
EEA European economic Area
EEC European Economic Community
EES Eastern Energy System (Mongolia)
EFTA European Free Trade Association
EIB European Investment Bank
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ENTSOe European Network Transmission System Operators for Electricity (formerly European Transmission System operators ETSO)
EP European Parliament
EPA Economic Partnership Agreement
EPC Engineering Procurement and Construction
EPR Empresa Propietaria de la Red (Central America)
EOR Ente Operador Regional (Central America)
ERBD European Bank for Reconstruction and Development
ERC Energy regulatory Commission (Mongolia)
ERERA ECOWAS Regional Regulatory Authority
ESC European Stakeholder Committee
ESIA Environmental and Social Impact Assessment
ERC Energy Regulatory Commission
EU European Union
FDI Foreign Direct Investment
FIT Feed-In Tariff
FMO The Netherlands Development Finance Company (Bank)
FTR Financial Transmission Rights (EU)
FSM Frequency Sensitive Mode
GCCIA Gulf Cooperation Council Interconnection Authority
GCC-IA Gulf Cooperation Council Interconnection Agreement
GE General Electric
GESP Generation Expansion Simulation Programme
GIS Geographical Information System
GoM Government of Mongolia
HPA Heat Purchase Agreement
HPP Hydro Power Plant
HSCB Hong Kong & Shanghai Banking Corporation (Bank)
HV High Voltage
HVAC High Voltage Alternative Current
HVDC High Voltage Direct Current
ICA Infrastructure Consortium for Africa
ICBC Industrial and Commerce Bank of China
IEA International Energy Agency
IEM Internal Electricity Market (EU)
IFC International Finance Corporation
IGMOU Inter-Governmental Memorandum of Understanding
INDC Intended Nationally Determined Contribution (Climate Change)
ING Internationale Nederlanden Groep (Bank)
IPO Initial Public Offer
IPP Independent Power Producer
IRR Internal Rate of Return
IUMOU Inter-Utility Memorandum of Understanding
JICA Japan International Cooperation Agency
KEPCO Korea Electric Power Corporation
KOICA Korea International Cooperation Agency
LCOE Levelized Cost of Electricity
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LLC Limited Liability Company
LFSM-O Limited Frequency Sensitive Mode at Over-frequency
LFSM-U Limited Frequency Sensitive Mode at Under-frequency
LUA Land Use Agreement at CHP5
MCDA Multi-criteria decision Analysis
MDB Multilateral Development Bank
MER Mercado Eléctrico Regional (Central America)
MFI Multilateral Financing Institution
MNT Mongolian Tugrik
MoE Ministry of Energy (Mongolia)
MOU Memorandum of Understanding
MP Member of Parliament
MSME Micro Small Medium Enterprises
MTI Merchant transmission Initiative (EU)
MUFG Mitsubishi UFJ Financial Group (Bank)
NAPSI Northeast Asia Power System Interconnection
NAPSI-SC Northeast Asia Power System Interconnection Supervision Centre
NC Network Code (EU)
NDC National Dispatching Center (Mongolia)
NEA North East Asia
NEPAD New Partnership for Africa’s Development NGC National Grid Company (UK)
NORDEL Nord Electricité - Coordination of the Transmission System Operators of Northern Countries of Europe
NRA National Regulatory Administration
NTC Net transfer Capacity (EU)
NTPG National Power Transmission Grid (Mongolia)
O&M Operation and Maintenance
OPEX Operational expenditure
OTC Over The Counter (EU)
PCI Project of Common Interest (EU)
PEAC Pool Energétique de l’Afrique Centrale
PPA Power Purchase Agreement
PRC People’s Republic of China
PTR Physical transmission Rights (EU)
PV Photovoltaic
RES Renewable Energy Source
REL Renewable Energy Act (Mongolia)
RfG Requirement for Generation (EU)
RMB Renmibi or Yuan
RMER Reglamento Mercado Eléctrico Regional (Central America)
ROK Republic of Korea
RTR Red de Transmisión Regional (Central America)
SADC Southern Africa Development Community
SAPP South Africa Power Pool
SB Soft Bank (Japan)
SES Southern Energy System (Mongolia)
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SIEPAC Sistema de Interconexión Eléctrica de los Países de América Central
SMBC Sumitumo Mitsui Banking Corporation (Bank)
SME Small Medium Enterprise
SMP System Marginal Price
SPC Special Purpose Company
SREP Scaling up Renewable Energy Program
SSF Shareholder Special Fund
TC Technical Cooperation
TEN-E Trans Europe Network - Electricity
TL Transmission Line
TPA Third Party Access
TPP Thermal Power Plant
TRAM Trade Related Assistance of Mongolia
TSO Transmission System Operator
TT Transmission Tariff
TRANSCO Mongolia Transmission Grid
TYNDP 10-Year Network Development Plan (EU)
UA Unit of Account
UB Ulaanbaatar
UCTE Union for the Coordination of the Transmission of Electricity (EU)
UK United Kingdom
UKFSOA United Kingdom Transmission System Operators Association
UNCTAD United Nation Conference on Trade And Development
UIOSI Use-It-Or-Sell-It (EU)
U-Q Voltage-Reactive Power
US United States (of America)
USD United States Dollar
USFC Ultra Super Critical Coal-fired
VAT Value Added Tax
VTB Vnechtorgbank (Bank)
WAPP West Africa Power Pool
WB World Bank
WES West Energy System (Mongolia)
WS Workshop
WTO World Trade Organization
WUA Water Use Agreement
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EXECUTIVE SUMMARY
The Module 6 report focuses on Power and Regulation between Northeast Asia countries.
The report presents experiences in the world of Regional Interconnection and lessons
learned from some of them and Regulation and Cost Recovery recommendations for imple-
menting a regional electricity market and facilitating the exportation of large scale renewable
generation in Mongolia.
Module 4 report has shown that Mongolian Solar and Wind power are the most cost-effective
of the NEA region. To remain cost-effective after transmission in the country of importation, it
is necessary to implement a mechanism where the cost recovery of the interconnectors does
not interfere with the cost of generation that are exchanged among the countries. This mech-
anism does exist in Europe and this is the one which is recommended for NEA Power Trade.
REGULATION FRAMEWORK AT REGIONAL LEVEL The report recommends at first step to implement a strong coordination among the Regula-
tors of Mongolia, PRC, ROK, Japan and Russia:
For establishing a common set of rules
For organizing and monitoring the National Regulation modifications
If no Regulators are designated so far, the Ministry of Energy can represents the country.
The report recommends the creation of a NAPSI Authority for managing the interconnection
infrastructures and for ruling the harmonization of the national Regulations at regional level:
Development of a Regional Regulation regarding:
. Mission to National Regulatory Authorities (NRAs)
. Free regional market for all players
. Power trade contracts standardization
. Institutionalization of competitive mechanisms
. Regional Grid Code: Clear common rules
. Transmission rights: Development of comprehensive methodology
. Same priority for domestic demand and export commitments
Modification of the National Regulations regarding:
. Third Party Access (TPA): Transparent and non-discriminatory access to intercon-
nection has to be guaranteed for all players especially IPP
. Independence of National Regulatory Authorities (NRAs) encouraged by law
The report recommends also the elaboration of a NEA Grid Code
INTERCONNECTOR FINANCING The report recommends that the Regulated regime for a new interconnector between 2
TSOs, letting open the option of a financing wholly or partly by the private sector.
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The advantages of a strong coordination between the regulators/ministry of Energy of the 5
countries is that it is possible to organize additional grants to complete the profitability and
compensate the benefit for the other TSO of the ring that are not involved directly by the new
interconnection.
INTERCONNECTOR COST RECOVERY BY TRANSMISSION RIGHT AUCTIONS The report recommends for cost recovery of the interconnectors, the mechanism in operation
in Europe that is based on a separation between 2 businesses:
The business of Interconnection service
The business of Generation
The value of this mechanism is that the cost of Transmission through the interconnector can’t affect the cost of generation, avoiding the risk that the low price energy produced in the ex-
porting country could become non-cost effective in the importing country.
To sum up how it works:
The interconnection business make sense each time there is a price difference between
the 2 countries: the exporting country (low price) and the importing country (high price).
The difference between high and low price is called the Economic Congestion Rent.
The 2 involved TSOs sell through auctions the Transmission Rights to Traders through
Auctions. The price paid for the TRs represent a cost for the Trader.
The Trader buys energy in the exporting country and sell it in the importing country. The
profit between the sale and the purchase of energy due to the congestion represents a
revenue for the Trader.
The profit of the Trader is the difference between his revenue based on the congestion
rent and his cost of transmission rights.
The result is that the generation company sells more energy through the interconnection at
cost effective low price of the exporting country while the traders make profit on the intercon-
nection service only in buying the low price energy of the exporting country and selling it into
the high price importing country.
MONGOLIA GRID UPDATE THROUGH 500KV HVAC The Module 5 report on Power System Interconnection studies recommends that taking into
consideration the high volume of Renewable Energy produced in Mongolia (5GW, 10GW and
100GW) compared to the existing consumption (1GW), the upgrade of the existing Mongoli-
an grid is mandatory. The recommended solution in the Module 5 report is a 500kV HVAC
grid that gives the opportunity both to unify the 5 existing sub-systems and to interconnect
Mongolia with Russia and China.
The Module 6 report suggests 2 solutions for the financing and cost recovery of the recom-
mended 500kV HVAC grid upgrade:
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Option N°1: consider the Mongolia Grid Upgrade an interconnection part of the NEA Ring
and organize it by the NEA coordination (preferred solution through the NAPSI Authority)
through a Built Own Operate Transfer (BOOT)
Option N°2: consider the Mongolia Grid Upgrade an interconnection between China and
Russia and organize it through a Built Own Operate Transfer (BOOT) by a Russian &
Chinese consortium.
The report suggest for both options the same cost recovery methodology that is the same as
recommended above: through Transmission right auctions based of congestion rent valoriza-
tion.
MONGOLIA CONVENTIONAL GENERATION COST RECOVERY The Paris agreement represents new deal for coal-fired generation: only some lenders
still may provide financing for coal-fired Power Plants according to information we have
collected verbally
Hybrid (electricity and grid) may still be possible by Western financing as long as it con-
tributes only to stabilized the output of renewable generation
NEW REGULATION FOR IMPROVING ATTRACTIVENESS OF PRIVATE FOREIGN AND LOCAL INVESTORS IN MONGOLIA The Module 6 report recommends that the Mongolian regulation:
gives enough visibility on the renewable energy policy targets and market volume:
The foreign investors would come to a new country if they see a sufficient volume of projects
they can invest in for the long term. The visibility horizon should be at least 10 years on En-
ergy Policy with good level of monitoring by the Government,
ensures foreseeable and stable Revenues:
Renewable energy projects need some clarity on the long term electricity price and on ۔
the electricity market mechanisms. Investors require foreseeable and guaranteed reve-
nues. The same for the taxes.
-In case of Feed in Tariff: the calculation should allow extra revenue in case better per ۔
formance than expected.
guaranties the Grid Operation: Priority dispatch / no curtailment:
The Wind and Solar energies are intermittent but need to be able to inject when wind is blow-
ing or sun is shining. Moreover, procedure of compensation have to be clear and guaranteed
in case of Grid failure.
guaranties the Grid connection with enough capacity on short and long runs
improves the Contractual and Legal maturity:
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The legal context in which renewable projects will be built need clarity and stability (clear and
stable frame for permitting, sale of electricity, tax, etc…).
develops adequate Financing facilities:
-The renewable energy projects are very CAPEX intensive. It is crucial that financing insti ۔
tution feel comfortable in financing renewable projects.
-With Fixed Interest Rates, no exchange rate risk long term debt compliant with Tariff pe ۔
riod of guaranty allowing gearing at least of 80%.
gets reliable pre-permitted sites
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1 BENCHMARK OF REGIONAL INTERCONNECTIONS
1.1 OBJECTIVES
Several cases of regional interconnection have been reviewed in introduction to the Power Trade and
Regulation report. The list is described in table 1.
Region Interconnec-tions
Status
Europe In operation In operation – 36 countries
Asia ASEAN
Central Asia
GCC-IA
In construction – mainly bilateral agreements
In operation – multilateral agreement
In operation
North America Canada - US In operation
South America SIEPAC In operation
Africa North,
SAPP, EAPP
WAPP
In construction/in operation
In operation and construction Focus on
WAPP
Table 1 : The studied regional interconnections
Focus for Strategy for NAPSI
In all cases, a strong coordination among the entities in charge of Market regulation has
been implemented.
The Module 6 report on Power Trade and Regulation report is going to develop the most
representative cases on 3 continents:
Africa, especially the West Africa Power Pool (WAPP)
Central America : SIEPAC (Sistema de Interconexión Eléctrica de los Países de América
Central)
Europe
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1.2 AFRICA INTERCONNECTION
1.2.1 General Description
Several interconnection grids are being established in Africa. Several power pools in North,
West, Central, South and East Africa will be able to deliver power on large-scale energy
bases; giving full play to hydropower as a moderator to support the development of wind and
solar. Africa-Europe power channels for the transmission of energy surplus to Europe have
been envisaged.
Figure 1 : African Power Pools
1.2.2 Existing Interconnections
Current situation of grid interconnection in Africa
Africa is at a relatively low level of energy integration, and its energy trade is dominated by
fossil energy while its cross-border power interconnection is at the initial stage.
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However, large internal market capacity exists. During the period 2010-2016, the average
annual growth rate of personal expenditure in Africa was 3.6 %.
In the future, Africa's domestic power will be improved significantly along through rapid popu-
lation growth and promotion of industrialization and urbanization.
Interconnection infrastructure are necessary to accelerate the achievement of the sustaina-
ble development in Africa. Clean energy resources are important in Africa with large total
amount, various types, and huge development potential. However, the clean energy re-
sources have to be shared among African countries. Some landlocked countries suffer a lack
of energy resources. Therefore, interconnection of energy resources is urgently needed to
achieve mutual aid and complementation. Power Pools are expected to (a) achieve large-
scale development, allocation and use of clean energy, and (b) transform the resource ad-
vantage into the economic advantage.
The energy trade in Africa is dominated by the export of raw materials and the import of fin-
ished products, with a relatively small power exchange capacity. The gross volume of energy
import and export is about 657 MTOE, consisting of 48.8% of crude oil export, 14% of oil
products import and only 0.8% of power trade. Oil and gas pipeline networks are of a rela-
tively high density and interconnected in North Africa, Inter-continental oil and gas pipelines
has been built between African countries (i.e. Morocco, Algeria, Tunisia, Libya), Middle East
(Egypt and Jordan) and European countries (i.e. Spain, Italy and Malta).
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Figure 2 : Africa Transmission Grids
1.2.3 Main Targets of work
The whole Africa is relatively abundant in clean energy which is mainly distributed in deserts,
rainforests and other sparsely populated and economically underdeveloped regions in a way
reverse to that of the need. Large hydropower, solar power and wind power bases need to
be developed in a centralized way to transmit power in a large scale and across a long dis-
tance to the load center to satisfy the power demands of densely populated areas for eco-
nomic and social development. Compared with distributed power generation, centralized
power generation has the advantages of economies of scale, and is reliable and maintaina-
ble. At present, the centralized development cost of all countries in Africa is about 30% -50%
that of distributed development. It is estimated that by 2050 the centralized solar power gen-
eration cost will be 30% -40% lower than that of distributed solar power development. In re-
mote rural areas, mountainous areas and sparsely populated areas, it is suitable to adopt
distributed photovoltaic and small hydropower plants to meet power demand.
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Figure 3 : Main targets for each African Power Pool
Realizing sustainable clean energy and power supply.
In the future, energy and electricity needs of African economic and social development will
be met in a clean and green way, getting rid of dependence on fossil energy and realizing
sustainable clean energy and power supply. By 2050, the proportion of clean energy to pri-
mary energy will be more than 45%, and electricity generated by clean energy will account
for about 73% of African total electricity generation.
Stimulating economy growth.
Constructing Africa Energy Interconnection will greatly stimulate emerging industries such as
new energy, power, mining, smelting, processing, etc., and therefore forge a new engine for
African economy growth. Total investment for Africa Energy Interconnection is about 2.9 tril-
lion USD, which will raise annual average economy growth by 0.4 percentage points.
Reducing development cost.
Through large-scale exploitation of clean energy with low marginal cost, Africa’s average power supply cost will effectively decrease. By 2050, the LCOEs (Levelized Cost of Electrici-
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ty) of various power sources can all reach 9 cents/kWh and below (Fig. 6.1). Africa’s average LCOE will be 8.6 US cents/kWh. This cost is about 5.1 US cents/kWh lower than the present
level, leading to about 158 billion USD electricity cost be saved annually.
Figure 4 : Prediction of average cost per kWh of various power sources in Africa
(US cent/kWh)
Increasing foreign exchange earnings.
Through large-scale exploitation of clean energy power generation bases and cross-border,
inter-regional and inter-continental interconnections, clean power delivery and consumption
will be achieved, which will also vigorously expand the scale of the import and export trade of
electricity. By 2050, Africa’s electricity import and export trade will generate about 30 billion USD in foreign exchange earnings.
Realizing balanced development.
Africa is comparatively less developed with on the contrary abundant clean energy re-
sources, but it can convert the resources advantage into economic superiority, which will
potently boost economy. African people could have fair chance of developing. The wealth
gap will be reduced, the unbalanced economy development and poverty issues will be set-
tled.
1.2.4 Organization and Responsibilities
Africa has established some regional energy and power organizations, including New Part-
nership for Africa's Development (NEPAD) and the Association of Power Utilities of Africa
(APUA) and regional power pools.
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Figure 5 : APUA and NEPAD logos
These organizations promote cross-border grid interconnection, establish a unified electric
power market and realize efficient energy and power development by joint planning, coordi-
nated regulation and design of power trading mechanisms.
Figure 6 : CEEAC-ECCAS, CEDEAD-ECOWAS and SADC logos
With these regional energy and power organizations, 35 African countries have realized grid
interconnection or cross-border direct power supply and have improved the foundation for
grid interconnection. Since the establishment of WAPP and SAPP, the number of intercon-
nected countries has increased by 40 % in West Africa and 50 % in Southern Africa.
Table 2 : African energy and power organization
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African countries have attached great importance to energy integration and laid a good foun-
dation for grid interconnection. Most African countries have similar history, industry structure
and resource endowment. In addition to political and economic integration, these countries
have also paid great attention to energy integration in recent years, to realize the goals of
reliable energy and power supply, efficient utilization of clean energy, reduction of energy
subsidies and energy exports for earning foreign exchange. On this basis, Africa has estab-
lished some regional energy and power organizations, including New Partnership for Africa’s Development (NEPAD) and the Association of Power Utilities of Africa (APUA) and regional
power pools. These organizations promote cross-border grid interconnection, establish a
unified electric power market and realize efficient energy and power development by joint
planning, coordinated regulation and design of power trading mechanisms.
The key points to achieve sustainable development in Africa are:
To properly exploit and utilize the rich, high-quality and centralized clean energy in Af-
rica
To greatly improve the electrification level
To accelerate the grid interconnection
To form a clean, safe and reliable energy development pattern.
1.2.5 Central African Power Pool
The documents governing the CAPP are:
the Inter-Governmental MOU,
the Inter-Utility MOU.
These two basic agreements created the current institutional framework for the CAPP
Organizational structure. This structure was organized to develop the components of the
power pool: its interconnected infrastructure and its governance system.
CAPP presently is the focal point for discussions on regional power markets; member states
of ECCAS rely upon CAPP for technical analysis of proposals for power sharing between
member states.
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Figure 7 : CAPP organizational chart
1.2.6 South African Power Pool
Four agreements govern the operation of SAPP, including bilateral trading. These agree-
ments are:
1. The Inter-Governmental Memorandum of Understanding which enables the establish-
ment of SAPP;
2. The Inter-Utility Memorandum of Understanding, which establishes SAPP’s basic management and operating principles;
3. The Agreement between Operating Members which establishes the specific rules of op-
eration and pricing; and
4. The Operating Guidelines, which provide standards and operating guidelines.
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Figure 8 : SADC organizational chart
SOURCE: Annual Report, SADC, 2018
1.2.7 East African Power Pool
The signature of the IGMOU was followed by the signature of an Inter-Utility MOU by the
Chief Executive Officers (CEOs)/Managing Directors of the countries’ of 9 Power Utilities.
This event heralded the formal launching of EAPP. Tanzania has consequently signed the
relevant MOUs in March 2010 and became the member of EAPP.
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Figure 9 : EAPP organizational chart
1.2.8 West African Power Pool
ECOWAS is the West African Economic Community which regroups together 15 countries of
Western Africa.
The West African Power Pool (WAPP) represents the regional legal and operational frame-
work favorable to energy exchanges and to protecting the investments in the countries of the
region.
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Table 3 : WAPP implementation framework
Overall missions of ERERA:
Regulation of the cross-border power pooling among ECOWAS Member State
Implementation of the conditions to ensure rationalization and reliability
Setting up a regulatory and economic environment suitable for regional market
Compliance with the principle of freedom of electricity transit
Establishment of a clear, transparent and predictable tariff setting methodology for re-
gional power pooling
Technical regulation of regional power pooling and the monitoring of regional market op-
erations
Assistance to the ECOWAS Commission in defining the strategic direction of the regional
policy and the harmonization of policies, legislations and regulation of national power
sectors
Effective dispute resolution between regional power market players
Partnership relations with national regulatory authorities in Member States and provide
them with technical advice and assistance at their request
Communication among the various actors in the sector.
The ECOWAS Regional Electricity Regulatory Authority (ERERA) is the regional regulator for
cross-border electricity interconnections in West Africa.
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Figure 10 : ECOWAS organizational chart
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THE DEVELOPPEMENT OF WAPP
Phase 1: started in June 2018 Free bilateral Power Trade: mutual agreement.
Negotiated prices including both Transmission + Generation
Figure 11 : WAPP Phase 1
Phase 2: 2020-2022
Mutual Agreement with Regulated Transmission Tariff: MW.km point-to-point distance.
Market (Day Ahead): Postage Stamp Tariff
Customer pays 100% of Transmission prices
Figure 12 : WAPP Phase 2
Phase 3: after 2022
Regulated Transmission Tariff : Local Marginal Price / Nodal Price
Figure 13 : WAPP Phase 3
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1.2.9 Next Steps
1.2.9.1 Phased Implementation scheme
The Africa Energy Interconnection shall take initial shape by 2030. Inter-regional synchro-
nous grid interconnection will be realized between East Africa and Southern Africa, as well
as West Africa and Central Africa. Meanwhile, inter-continental grid interconnection will be
realized among Asia, Europe and Africa.
With power grids in different countries and regions being improved continuously, in terms of
intra-continental interconnection, the D. R. Congo-Guinea, Ethiopia- South Africa and Came-
roon-Nigeria DC projects will be constructed, to transmit hydropower generated in Inga on
the Congo River, the Nile River and the Sanaga River to load centers of West and Southern
Africa. In terms of inter-continental interconnection, Morocco-Portugal and Tunisia-ltaly DC
projects will be constructed to transmit solar power of North Africa to Europe, realizing grid
interconnection of Africa and Europe; Saudi Arabia-Egypt DC project will be constructed to
realize grid interconnection of Asia and Africa.
Figure 14 : Schematic diagram of African overall power grid pattern in 2030
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By 2040, Africa will form “one-horizontal and two-vertical” backbone power grids, and inter-continental grid interconnection channels will be further strengthened. In terms of
intra-continental interconnection: D. R. Congo-Nigeria DC project will be constructed to ex-
pand the transmission scale of hydropower generated on the Congo River; 1,000 kV AC
power transmission channel of North Africa crossing the five countries will be constructed, to
connect the large solar power bases and load centers. The power transmission channel con-
nects the Western Asia power grid, achieving mutual complementation between North Africa
and Western Asia. In terms of inter-continental interconnection, Egypt- Greece-ltaly DC pro-
ject and Algeria-France DC project will be constructed to further expand the scale of solar
power transmission from North Africa to Europe; Saudi Arabia-Egypt and Ethiopia-Saudi
Arabia DC projects will be constructed to improve the mutual complement capacity of power
among North Africa, East Africa and West Asia.
Figure 15 : Schematic diagram of African overall power grid pattern in 2040
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By 2050, with strong Energy Interconnection basically established, Africa will have “two-
horizontal and two-vertical” backbone power grids and the scale of Asia, Europe and Africa Interconnection will grow continuously. In terms of intra-continental interconnection: The
1,000 kV AC power transmission channel of North Africa and 765/400 kV AC main power
grids of other regions would be further improved. North, Central & West and East & Southern
Africa power grids will form 3 strong synchronous power grids. DC interconnection among
synchronous power grids will be improved and the D. R. Congo-South Africa, D. R. Congo-
Ghana, 2nd D. R. Congo-Guinea, D. R. Congo-Morocco and D. R. Congo-Ethiopia DC pro-
jects will be constructed. The hydropower of East Africa and solar power of North Africa will
complement with each other. In terms of inter-continental interconnection, Morocco-Spain
and Algeria-France- Germany DC projects will be constructed to transmit hydropower of the
Congo River, co-regulated with solar power of North Africa, to the load centers of the conti-
nental Europe.
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Figure 16 : Schematic diagram of African overall power grid pattern in 2050
1.2.9.2 Investment Estimate
Investment in the Africa Energy Interconnection consists of power source investment and
power grid investment. Power source investment shall be calculated based on unit invest-
ment cost and capacity put into operation of each horizon, while power gird investment shall
be estimated based on power grid investment cost of each voltage level.
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In view of the development trend of various power source technologies and based on re-
search results of International Energy Agency, International Renewable Energy Agency,
Bloomberg New Energy Finance and other international energy agencies, it is predicted, af-
ter calculation, that the unit investment cost of solar power and wind power will decrease by
70 % and 50 % by 2050 compared with those in 2015, respectively. By then, the unit invest-
ment cost of PV will decrease to 550 USD/kW, solar thermal power to 2,000 USD/kW, on-
shore wind power to 800 USD/kW and offshore wind power to 2,500 USD/kW.
For power grid investment, the investment in UHV grid is estimated by referring to that of
similar projects in China, and is also adjusted as appropriate based on that of similar projects
in Africa and surrounding countries. Investment in 220/400/500/765 kV power grids is esti-
mated based on those of similar projects in the region. For power grids below 400/500/765
kV, the investment is considered as 1:5 to those of 400/500/765 kV power grids.
Table 4 : Parameters of power grid investment estimate of each voltage level
By 2050, the total investment of Africa Energy Interconnection is 2.9 trillion USD. 1.58 trillion
USD will be invested in new power generation, including 1.38 trillion in clean energy (ac-
counts for 86.9%). 1.32 trillion USD will be invested in power grid construction (accounts for
46%). Investments of regional energy interconnections are shown below.
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Figure 17 : Investment in power interconnection of different regions in Africa
from 2018 to 2050
1.2.10 Conclusions: Lessons Learned For NAPSI
Africa Interconnection is developed in the frame of Economic Cooperation be-tween States
Several Power Pool are operational in Africa
Electricity Market integration are ruled by Regulatory Coordination bodies
Distance Transmission tariff are implemented with possible nodal pricing in the future
1.3 SOUTH AMERICA: SIEPAC
1.3.1 General Description
SIEPAC is the supranational initiative developed by six Central American nations (Panama,
Costa Rica, Honduras, Nicaragua, El Salvador and Guatemala). The interconnection is now
in operation.
The first interconnection discussions were in 1987.
It began with the Framework Agreement of the Electrical Integration of Central America (97-
98) and the completion of the first circuit was done in 2013.
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The constructed new transmission lines connect 37 million consumers in Panama, Costa,
Rica, Honduras, Nicaragua, and El Salvador
Table 5 : History of SIEPAC
The development of the interconnection aimed to reach different objectives: Improve security of supply by widening reserve margins,
Reduce the problem of electricity rationing in capacity-deficit countries,
Achieve improved operating efficiency and reduce the amount of fuel consumption need-
ed for generating electricity,
Spur greater competition in domestic markets,
Lower end-user electricity costs,
Attract foreign investment to the region’s electricity sector, and Contribute to the economic development of the region.
Technology: Up to now, the transmission system includes 1 800 km of single circuit 230 kV transmission
lines, 15 substations, 300 MW + telecom infrastructure commissioned in 2013.
A second circuit is under construction.
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Figure 18 : Interconnection capacity of SIEPAC
1.3.2 Organization for Regulation and Operation of the SIEPAC Elec-tricity Market
Main entities:
CRIE Comisión Regional del Interconexión Eléctrica is the Regional Regulator based in
Guatemala, established in 2002 after the 1996 Electrical Market Treaty
EOR Ente Operador Regional is the Regional System Operator based in El Salvador,
established in 2002 after the 1996 Electrical Market Treaty
EPR Empresa Propietaria de la Red (Red de Transmisión Regional RTR) is the Grid Op-
erator based in Costa Rica, created in 1999, governed by private law, incorporated in
Panama comprising the public utilities and transmission companies of the six participat-
ing countries (66,6%) and extra regional shareholders (33,3%)
Mission of SIEPAC:
Provide a regulatory environment that facilitates a competitive Regional Electricity Market
(Mercado Eléctrico Regional MER) that contributes to expand and ensure sustainable elec-
tricity supply for the benefit of the inhabitants of Central America
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Table 6 : SIEPAC regulation modifications at national and regional levels
1.3.3 Organization for Regulation and Operation of the SIEPAC Elec-tricity Market
The development of SIEPAC’s physical infrastructure was mandated to under a build,
own and operate basis (BOOT), as provided in the 30-year concession granted by the
governments to the company though the Framework Agreement.
Monthly and annual auctions of transmission rights (DTs, derechos de transmisión) su-
pervised by CRIE.
The EOR carries out, for each auction, probabilistic forecasts of the nodal prices will give
the agents a reference on the prices of the DTs
Long-term transmission expansion planning is the responsibility of the EOR. The region-
al operator have to identify extensions of the RTR that maximize the social benefits of in-
jecting and ejecting agents, improve reliability at the regional level, and increase competi-
tion in the MER.
Long-term planning conducted with a horizon of ten years include information such as
transmission expansion plans for each country and the indicative planning for generation.
1.3.4 Power trade and tariff
Electricity sector and market structure of the six countries involved varies significantly, from
models based on fully competitive wholesale markets to vertically integrated utilities acting as
single buyers.
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MER was designed and operates as a separate market from the individual country markets,
mainly seeking to accommodate the different stages of development of local individual mar-
kets.
MER was design to use a nodal pricing system with auctioned capacity rights (firm transmis-
sion rights and financial transmission rights to hedge in case of network constraints) in a day-
ahead dispatch scheme with real-time balancing market.
1.3.5 Conclusion: Lessons Learned for NAPSI
SIEPAC Interconnection is developed in the frame of Economic Cooperation
between States
Electricity Market integration is ruled by one Regulatory Coordination Entity
The Cost recovery of interconnection infrastructures is a mixed of Transmission rights auctions Nodal transmission tariff
1.4 EUROPE
1.4.1 The stages of the European Union construction
The construction of the European Union (EU) is a long story starting with the Rome treaty in
1957, 12 years after the World War 2 between 6 countries France, Germany, Italy, Belgium,
The Netherlands and Luxemburg. Today, EU consists in 28 countries representing 500 mil-
lions of inhabitants.
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Figure 19 : The construction of the European Union
The figure above shows the staged integration of the 28 countries.
1st integration : United Kingdom, Ireland, Denmark (1973)
2nd integration : Greece (1981)
3rd integration : Spain, Portugal (1986) 4th integration : Austria, Sweden, Finland (1995) 5th integration: Cyprus, Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta,
Poland, Slovakia, Slovenia (2004) 6th integration: Bulgaria, Romania (2007) 7th integration : Croatia (2013)
In 1957, six countries founded the European Economic Community (EEC) and the European
Atomic Energy Community (EAEC), the origin of the European Union as we know it today.
These include Germany, Belgium, France, Italy, Luxembourg and the Netherlands.
1st integration: United Kingdom, Ireland, Denmark (1973)
During the 1950s, the United Kingdom had shied away from all attempts at European inte-
gration which might call into question its sovereignty, its relationship with its former Empire
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and its privileged relationship with the United States. But during the 1960s, the British reori-
ented their foreign policy towards an increasingly prosperous continental Europe.
In 1971, after two rejections by France, which feared a weakening of the Communities, the
United Kingdom saw the doors of the common market open. He was officially admitted on 1
January 1973, together with Ireland and Denmark.
2rd integration: Greece (1981) Greece had found itself diplomatically isolated since 1967. In 1974, Greece got closer to
Western Europe and submitted its application in 1975, but had to make up its economic
catch-up before becoming the tenth member of the European Communities on 1 January
1981.
3rd integration: Spain, Portugal (1986) Spain and Portugal were diplomatically isolated from the European construction. After long
negotiations, due to the economic fears raised by this accession, Spain and Portugal join the
European Communities on 1 January 1986, bringing the number of their members to twelve.
4th integration: Austria, Sweden, Finland (1995) Because of their military neutrality, a part of the European countries remained outside the
Community, preferring to join EFTA (European Free Trade Association). In 1991, the crea-
tion of the EEA (European Economic Area) extended the rules of the common market to the
EFTA countries.
The disappearance of the Soviet Union has rendered the status of a neutral country null and
void. For example, Austria, Sweden, Finland, Switzerland and Norway (which had already
done so in the early 1970s) apply for membership. In 1995, only the first three countries final-
ly joined what would become the European Union, bringing the number of its members to 15.
Norway and Switzerland reject accession by referendum.
5th integration: Cyprus, Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta, Poland, Slovakia, Slovenia (2004) The fall of the Berlin Wall in 1989 allowed the European continent to reunite.
Thirteen countries embarked on a process of accession to the European Union in the 1990s:
Cyprus, Malta, ten Central and Eastern European countries (Bulgaria, Estonia, Hungary,
Latvia, Lithuania, Poland, Czech Republic, Romania, Slovakia, Slovenia) and Turkey.
On 31 March 1998 accession negotiations began with the six best prepared countries: Cy-
prus, Estonia, Hungary, Poland, the Czech Republic and Slovenia.
Then, on 15 February 2000, six other countries followed: Bulgaria, Latvia, Lithuania, Malta,
Romania and Slovakia.
The Heads of State or Government decided at the Copenhagen European Council in De-
cember 2002 that Cyprus, the Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta,
Poland, the Slovak Republic and Slovenia met the criteria for joining the European Union.
They then proposed to them to join the European Union on 1 May 2004. On 16 April 2003,
the Accession Treaty of these 10 countries was signed in Athens.
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6th integration: Bulgaria, Romania (2007) The EU then signed an accession treaty with Romania and Bulgaria on 25 April 2005. The
European Council of 14 and 15 December 2006 endorsed the Commission’s favorable opin-
ion on the entry of these two countries into the Union.
On 1 January 2007 Bulgaria and Romania joined the European Community.
7th integration: Croatia (2013) The accession negotiations with Croatia began on 3 October 2005 and concluded on 30
June 2011.
Croatia became the 28th State of the European Union on 1 July 2013, after ratification of the
Accession Treaty signed on 9 December 2011, and the national referendum on 22 January
2012.
1.4.2 The Europe Power System Interconnection
The figure shows the electrical Europe
Figure 20 : The 5 synchronous zones of Europe power interconnection
The electrical Europe is wider that the Economic European Union.
The European Power System Interconnection consists today in 36 countries represented by
43 TSOs and in 5 5ynchronous Regions.
The construction of the electrical Europe can be summarized in 3 phases:
PHASE 1: 1956-1996 Common System Operation
During the electrical sector was structured around national vertically integrated monopoles.
The goals of the first phase was mainly:
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To develop the exchanges of electricity
To improve Grid Safety of each countries sharing a common System Operation
To Optimize the Cost of System operation and Grid and generation infrastructures
The operational rules of the same synchronous regions were harmonized between the mo-
nopolies under a first level of coordination bodies: ATSOI, UKTSOA, NORDEL and UCTE.
Figure 21 : Phase I of Europe power interconnection
PHASE 2: Since 1996, EU Electricity Market
During the 1990s, when most national electricity were still monopolized, the European Union
and the Member States decided to open the electrical markets gradually to competition. The
first liberalization directives (First Energy Package) were adopted in 1996 for electricity to be
transposed into Member States’ legal systems by 1998.
The cornerstone was the Third party access (TPA) policies that require owners of natural
monopoly infrastructure facilities to grant access to those facilities to parties other than their
own customers, usually competitors in the provision of the relevant services, on commercial
terms comparable to those that would apply in a competitive market.
TPA introduced deep changes in the Europe electricity sector:
Unbundling: 42 Transmission System Operators (TSOs) was created
Unbundling vertically integrated monopoles means splitting generation (production of
electricity) from transmission (of electricity from electrical generating station via a sys-
tem to a distribution system operator or to the consumer)
Private interconnections were allowed
The interconnections of different price zone markets
Each country had to publish their own set of Regulation and rules through National Grid
Codes.
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Coordination needs were reinforced with the creation of ETSO and then ENTSOe for coordi-
nating System Operation among the 42TSOs
Upon the emergence of the Internal Electricity Market (IEM) in the European Union, the
leaders of ATSOI, UKTSOA, NORDEL and UCTE recognized the need for an EU-wide har-
monization of network access and conditions for usage, especially for cross-border electricity
trade.
In 1999, the European Transmission System Operators (ETSO) was created as an associa-
tion with the four above-mentioned associations as founding members. However, on 29 June
2001 ETSO became an International Association with direct membership of 32 independent
TSO companies from the 15 countries of the European Union plus Norway and Switzerland.
Before its activities were transferred to ENTSO-E, ETSO represented 40 Transmission Sys-
tem Operator member companies. ETSO pursued scientific aims on a non-profit basis and
had the following objectives:
The study and development of common principles regarding the harmonization and
establishment of rules in order to enhance network operation and maintain transmis-
sion system security;
Facilitate the internal European market for electricity;
The communication and co-operation with organizations and institutions having simi-
lar objects;
The investigation and solution of scientific and regulatory issues of common interest
to the TSO industry.
On July 1st, 2009 ETSO was wound up. All operational tasks were transferred to European
Network of Transmission System Operator for Electricity ENTSO-e.
ACER for coordinating the Regulators
The Agency for the Cooperation of Energy Regulators (ACER), a European Union Agency,
was created to further progress the completion of the internal energy market both
for electricity and natural gas.
ACER was officially launched in March 2011, and has its seat in Ljubljana, Slovenia.
As an independent European structure which fosters cooperation among European energy
regulators, ACER ensures that market integration and the harmonization of regulatory
frameworks are achieved within the framework of the EU’s energy policy objectives. The lat-ter aim to create:
A more competitive, integrated market which offers consumers more choice
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An efficient energy infrastructure guaranteeing the free movement of energy across
borders and the transportation of new energy sources, thus enhancing security of
supply for EU businesses and consumers;
A monitored and transparent energy market guaranteeing consumers fair, cost-
reflective prices and the deterrence of abusive practices.
ACER is thus a central institution in the creation of a Single Energy Market to the benefit of
all EU consumers. One of the main important achievement of ACER was the European Net-
work Codes for harmonizing the National Grid Codes.
PHASE 3: EU Energy Policy, 20% of RES in 2020
The European plan on climate change consists of a range of measures adopted by the
members of the European Union to fight against climate change. The plan was launched in
March 2007, and after months of tough negotiations between the member countries, it was
adopted by the European Parliament on December 2008. The package focuses on emis-
sions cuts, renewables and energy efficiency. A first objective of 20% of Renewable Energy
by 2020 was decided.
The developed Interconnections have been revealed to be Key Assets for helping the Inter-
mittency Management bringing more opportunities in terms of flexibility and for facing the
European obligation for giving priority to the renewable energies in grid connection capacities
and System operation.
Figure 22 : Phase III of Europe power interconnection
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1.4.3 The European Regulation
The construction of the European Economic Community was a long run process that materi-
alizes through Legal Integration.
Table 7 : Definitions of the different levels of regulation in Europe
Each inferior level had to be compliant to the higher levels.
The European Commission examines and proposes legislation texts
The European Parliament discuss the texts.
The European Council validates and signs the legislation texts
1.4.4 The European Interconnection
The figure below slows the existing interconnections in EUROPE with their Net Transfer Ca-
pacity (NTC). NTC is the maximum exchange programme between two areas compatible
with security standards applicable in both areas and taking into account the technical uncer-
tainties on future network conditions.
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Figure 23 : Map of the Europe power interconnection with NTC in MW
This map is very simplified: only directions of exportation are represented. Directions of ex-
portation consists in several grid infrastructures (overhead lines, underground cable in some
cases and substations).
Example of France with neighboring countries consisting in 6 directions of interconnections
composed of a total of 30 interconnectors.
Since January 1st, 2006, The European Commission has allowed the TSOs to organize auc-
tions for Interconnection capacity reservation.
1.4.5 The European Internal Market Energy Packages
1.4.5.1 Description of the 3 Energy Packages
Europe’s regulatory production is very important in the electricity sector. It can be summa-
rized in 3 Energy1 Packages:
1 The Energy Packages included also regulation on gas.
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The First Energy Package was the first liberalization directives (Directive 96/92/EC)
adopted in 1996 to be transposed into Member States’ legal systems by 1998. It re-
quired:
. Regulators in charge of validation of National Grid Codes and arbitration
. Transmission System Operators (TSOs). When inside historic electrical companies
with unbundling based on functional separation between Generation and Grid. Legal-
ly independent, transparent and non-discriminatory in charge of Grid construction and
O&M and System operation.
. National Grid Codes
. The implementation of Wheeling Tariff
. The definition of thresholds for Eligible Consumers
. The creation of national Power spot Market
The Second Energy Package was adopted in 2003 for requiring a Target Market Model:
total and free Over The Counter (OTC) and a cross-border Regulation with a goal of 10%
of average interconnection rate. It was composed of:
. Directive 2003/54/EC to be transposed into national law by Member States by 2004,
with some provisions entering into force only in 2007 required that industrial and do-
mestic consumers are free to choose their own electricity suppliers from a wider
range of competitors.
. Regulation 1228/2003/EC8 network access to cross-border exchanges was adopted
in order to regulate transmission of electricity between member states and to estab-
lish the mechanisms for the compensation of the inter-transmission system operator,
the principles for its collection as well as for the use of the available interconnection
capacities among national transmission systems. Article 6 on congestion manage-
ment requires:
To use market based solutions
Maximum capacity to be ‘made available’ Unused capacity to be ‘reattributed to the market’ TSOs to apply netting ‘as far as technically possible’ Revenues to be used for increasing interconnection capacity
This second Energy Package was completed later by:
. Directive 2005/89/EC establishing measures aimed at safeguarding the security
of electricity supply, to ensure the proper functioning of the internal market for
electricity, an adequate level of interconnection between Member States, an ade-
quate level of generation capacity, and balance between supply and demand.
This Directive11 requires network operators to set and meet quality of supply and
network security performance objectives while member states need to encourage
the establishment of wholesale electricity markets
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. Decision No 1364/2006/EC of the European Parliament and of the Council of 6
September 2006 laying down guidelines for trans-European energy networks
. EC regulation 714/2009 on conditions for access to the network for cross-border
exchanges in electricity allows private interconnection with exemptions from cer-
tain aspects of the regulation for investments in cross-border lines in order to
stimulate investments that would not occur due to excessively high risk were ex-
emptions not in place.
The Third Energy Package in April 2009 required to further liberalize the internal elec-
tricity and gas markets was adopted, amending the second package and providing
the cornerstone for the implementation of the internal energy market.
The Third Energy Package consisted in 1 Directive and 2 Regulations for electricity:
. Directive 2009/72/EC concerning common rules for the internal market in elec-
tricity
. Regulation (EC) No 714/2009 on conditions for access to the network for cross-
border exchanges in electricity
. Regulation (EC) No 713/2009 of the European Parliament and of the Council of
13 July 2009 establishing an Agency for the Cooperation of Energy Regulators
Main decision was referring to the creations of
ACER Agency for the Cooperation of Energy Regulators
ENTSOe European Network Transmission System Operator for electricity
European Network Codes
The European Commission and the Parliament wanted boost the correct transposition of the
previous Directives. Because of this, the Third Internal Energy Market Package was adopted
in 2009 to accelerate investments in energy infrastructure to enhance cross border trade and
access to diversified sources of energy.
1.4.5.2 The Regulatory Coordination by ACER ACER is a new body which complement the regulatory task of the national level and which is
completely independent from the European Commission, national governments and energy
companies. The reason for ACER being established goes in hand with the strengthening of
the regulatory powers as well with solving the gaps in cross-border projects regulation. Also,
the Agency is responsible for ensuring and promoting effective cooperation between national
regulatory authorities at regional and Community level and to take decisions on cross-border
issues if national regulators cannot agree or ask ACER to intervene.
ACER is responsible for the review of the implementation of the EU network development
plans and for monitoring the functioning of the internal market, including retail prices.
Available network access, especially for electricity produced from renewable energy sources
and compliance with the consumer rights is also within ACER’s responsibilities.
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ACER has also the competence to investigate cases of market abuse and to coordinate the
application of appropriate penalties with the Member States. The responsibility for applying
sanctions applicable to infringements lies, however, in the hands of the Member States.
The European Agency for the Cooperation of Energy Regulators (ACER) has been opera-
tional since March 2011.
1.4.5.3 The TSO’s coordination by ENTSOe As a further step, the regulations Regulation (EC) No 715/2009 was adopted, creating struc-
tures of cooperation for European Network Transmission Systems Operators (ENTSOs). The
ENTSOs, together with ACER, create detailed network access rules and technical codes,
and ensure the coordination of grid operation through the exchange of operational infor-
mation and the development of common safety and emergency standards and procedures.
ENTSOs are also responsible for drafting a 10-year network investment plan every two
years, which are then in turn reviewed by ACER.
1.4.5.4 The Florence Forum
The Electricity Regulatory Forum, also referred to as the Florence Forum, was set up to
discuss the creation of the internal electricity market. Since 1998, the forum has met once
per year in Florence, Italy. Its participants include national regulatory authorities, Member
State governments, the European Commission, TSOs, electricity traders, consumers, net-
work users, and power exchanges.
1.4.5.5 The Europe Network Codes Network codes are a set of rules drafted by ENTSO-E, with guidance from the Agency for the
Cooperation of Energy Regulators (ACER), to facilitate the harmonization, integration and
efficiency of the European electricity market. Each network code is an integral part of the
drive towards completion of the internal energy market, and achieving the European Union’s energy objectives.
ENTSO-E’s network codes are binding pan-European rules drafted by ENTSO-E in consulta-
tion with stakeholders, with guidance from ACER. Network codes are grouped in three areas:
connection codes connecting electricity generators, demand, and direct current lines
to the transmission grids
operational codes governing how the pan-European electricity systems are operate
market codes facilitating and harmonizing electricity trading across European borders
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Table 8 : The Network Code family
The connection Network Codes
The Network Code on Requirements for Generators (RfG) was the first Code to be dis-
cussed and validated. RfG is harmonizing standards that generators must respect to con-
nect to the grid. These harmonized standards across Europe as designed for boosting the
market of generation technology and increase competitiveness.
The Network Code on High Voltage Direct Current Connections (HVDC) specifies re-
quirements for long distance direct current (DC) connections. These are used to link offshore
wind parks to mainland or to connect countries over long distances (for example the longest
existing interconnector in Europe, NorNed, links Norway and The Netherlands with an HVDC
submarine cable of 580 km long).
The Demand Connection Code sets harmonized requirements for connecting large renew-
able energy production plants as well as demand response facilities. The code will ease the
integration of 260 gigawatts of photovoltaic & wind (almost tripling the current installed ca-
pacity in Europe) as well as 11 gigawatts of demand response in Europe (which could mean
the sparing of 11 coal generation plants).
The Operation Network Codes
The Emergency & Restoration Code fixes the processes that the transmission system op-
erators must follow when they face an incident on their grid. The highest standards and prac-
tice in dealing with emergency situations will thus apply in all Europe.
The System Operation Code specifies what transmission system operators should do in
managing their grid. The fact that the generation mix in Europe is integrating more and more
renewables, that there is more and more interconnections and cross-border competition has
been considered in the System Operation Guideline. It lays the ground for the next power
system and for example makes regional coordination a legal obligation for grid operators.
The Market Network Codes
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The Electricity Balancing Code is about creating a market where countries can share the
resources used by their transmission system operators to make generation equal demand
always. It is also about allowing new players such as demand response and renewables to
take part in this market. All in all, the Balancing Guideline should help increase security of
supply, limit emissions and diminish costs to customers.
The Network Code on Forward Capacity Allocation deals with rules for long term mar-
kets, the forward markets. These have an important role in allowing market participants to
secure capacity on cross border lines a long time in advance and therefore have a sort of
trade insurance.
The Code on Capacity Allocation and Congestion Management sets out the methods for
calculating how much space can market participants use on cross border lines without en-
dangering system security. It also harmonizes how cross border markets operate in Europe
to increase competitiveness but renewables’ integration. CACM is the cornerstone of a Euro-pean single market for electricity.
The drafting and adoption process of network codes is defined by the Third Package. ACER
develops a framework guideline setting the policy choices for each code. On this basis, the
codes are drafted by ENTSO-E in consultation with stakeholders. After ACER’s opinion and recommendation for adoption, each code is submitted to the European Commission for ap-
proval through the Comitology process, i.e., to be voted on by Member State representatives
and thus to become EU law, directly binding and implemented across all Member States.
Since 2011, considerable effort has been devoted to the development of the Network Codes.
The involvement of stakeholders such as consumer organizations, generators, suppliers and
many others from across the European electricity sector has in particular been key to the
successful adoption of an efficient set of Network Codes. All the Network codes are set into
force since January 1st, 2017.
Following the entry into force the Network Codes, the European Network Codes Stakeholder
Committees, chaired by ACER, was implemented for insuring that throughout the implemen-
tation program, stakeholders are kept abreast of developments and provided with a forum to
express their views and feedback.
1.4.5.6 European Stakeholder Committees
ACER and ENTSO-E are organizing European Stakeholder Committees (ESCs), one per
family of codes (Market codes, Operational codes and Connection codes). These Commit-
tees aim to complement, and not to replace, the legal obligations of stakeholder consultation
and information included in the NCs during the implementation period.
The main objectives of the ESCs are:
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1. To contribute to monitoring progress in the NCs implementation process – as well as
the operation and functioning of the processes and arrangements established accord-
ing to the NCs – at local, regional and pan-European level as an overarching struc-
ture of all network codes;
2. To serve as a platform to share general views on the NC implementation, with a par-
ticular focus to enable stakeholders to express their views and receive feedback;
3. To contribute to a more informed decision-making process for the methodologies and
rules still to be developed for the implementation of the NCs.
1.4.6 The Europe 10-Year Network Development Plan
Long-term network development plan is one of the core missions of any transmission system
operator (TSO). It allows them to tailor grids to the evolution of demand and generation, se-
curing an affordable supply of energy for customers in the next decades.
Since 2009, the European legislator has tasked ENTSO-E with the delivery of a European
network development plan which builds on national plans and includes specific regional in-
vestment plans. Having a European approach to grid planning ensures consistency and cost-
efficiency.
Without a well-functioning market, adapted legislation and the proper infrastructure in place,
Europe cannot guarantee the decarbonization of its economy, the development of its internal
energy market and its security of supply. The TYNDP is thus key to many of Europe’s eco-nomic, climate and energy objectives.
Each TYNDP takes two years to complete. The first edition was issued in 2010.
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Table 9 : TYNDP in numbers
Figure 24 : Map of the latest TYNDP
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1.4.7 The Trans-European Network TEN-E and Project of Common in-terest PCI
Key cross border infrastructure projects that link the energy systems of EU countries are
called priority corridors.
Project of Common Interest (PCI) helps the EU to achieve its energy policy and climate ob-
jectives: affordable, secure and sustainable energy for all citizens, and the long-term decar-
bonization of the economy in accordance with the Paris Agreement. In practice, the CBA of a
PCI should be positive.
Figure 25 : The Projects of Common Interest
PCIs may benefit from accelerated planning and permit granting, a single national authority
for obtaining permits, improved regulatory conditions, lower administrative costs due to
streamlined environmental assessment processes, increased public participation via consul-
tations, and increased visibility to investors.
They also have the right to apply for funding from the Connecting Europe Facility (CEF).
1.4.8 The regimes for Interconnection in Europe
The 2 basic regimes for interconnection in Europe are the Regulated Regime and the Private Regime. The Regulated regime is designed for non-discriminatory access. The revenues are fully regulated and controlled by NRAs with consumer underwriting The Private regime also called Merchant Transmission Initiative (MTI) is allowed under con-ditions
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There is now a new hybrid regime in development by UK called « Cap & Floor » that is offer-
ing a risk mitigation to private sector.
1.4.8.1 The Regulated regime
Figure 26 : New interconnection involving 2 TSO’s B&C can benefit to others A&D
The Europe interconnector cost recovery in the Regulated regime:
1. Basic rule: the benefits of New Interco are shared 50%/50% between TSO B and
TSO C
2. There is no rules for Cost Sharing : it depends on the Project
3. The regulated investment cost recovery methodology is the following
If the new interconnector is eligible to PCI, the Social Welfare that benefits A&D without they
fund the New Interconnectors may be compensated by Grants from EU Funds.
For example by the EU find called CEF Connecting Europe Facilities (CEF) dedicated to in-
frastructure as transport, energy and digital.
The difference between Investment costs bared by the TSO B and C and the Grants is se-
cured by B&C Transmission Tariffs (consumer underwriting).
Complementary revenues can limit the pressure on B&C tariffs:
Auctions for allocating Transmission Rights according to “Use-it-or-Sell-it” principle (UIO-
SI)
. Explicit (Physical transmission Rights PTRs) or implicit (Financial Transmission
Rights - FTRs) auctions
. PTRs: Yearly, Seasonal, Quarterly, Monthly, Daily, Intra-day
On Capacity Mechanisms of B&C
On Balancing Markets of B&C
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1.4.8.2 The Private regime
The Private regime is also called Merchant Transmission Initiative (MTI). The principles are
the followings:
Being a profit-motivated investment, MTIs are exempted from Regulation Constraint.
As a result, merchant lines are funded at 100% by private investors and all revenues go
to the private investor for a limited period.
The owner can freely chose the methodology for cost recovery: power flow tariff or
Transmission Right auctions (similar to regulated regime). He can get complementary
revenue on Capacity Mechanisms and on Balancing Markets of B&C.
The MTI is allowed under conditions checked by the Regulators of the involved countries:
1. Investment must enhance competition in electricity supply
2. Risk of project is so high that investment would not take place
without exemption of regulated model being granted
3. Interconnector must be owned by a legal entity separated from the regional System
Operator
4. Charges are levied on the users of the interconnector
5. No parts of CAPEX or OPEX have been recovered from Transmission or Distribution
tariff to which the interconnector is connected
6. Exemption must not come at the cost of ineffective operation of internal electricity
market or inefficient functioning of regulated system governing interconnector
7. If the conditions are met, private interconnector project can be exempted from regula-
tory requirements. The owner can benefit a private access for a limited period. And
the revenue can be freely determined by the owner. For private projects there is no
consumer underwriting.
Here are 2 examples of existing MTIs:
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Figure 27 : 3 examples of Merchant Transmission Initiative (MTI)
Eastlink (2005): 105 km. 350MW submarine HVDC Finland and Estonia between 25
years for the use of congestion revenues and Regulation exemption. Now ownership
transferred to Finnish and Baltic TSOs. Capacity fully reserved for Baltic Generation
companies (one way from Baltic to Finland).
Britned (2007): 260km. 1000MW submarine HVDC between the Netherlands and UK
owned by the TSOs NGC and Tennet. 25 years for the use of congestion revenues and
Regulation exemption. The cost recovery methodology is the sale of Transmission Rights
with explicit and implicit auctions.
East-West cable Imera (2008): 262km. 1000MW submarine HVDC between Ireland and UK
(Wales). 25 years for the use of congestion revenues and Regulation exemption. Long terms
contracts with a cap of 40% for ESB. The owner is Imera a private investor which is not mar-
ket players.
1.4.8.3 The CAP and FLOOR Regulatory regime Cap & Floor is a new regime open to electricity interconnectors in UK first applied for the
undersea cable called NEMO (UK- Belgium) allowed as an incentive for private sector offer-
ing a risk mitigation.
It is a developer-led approach incentivizing investment through a market-based approach,
with appropriate risks and rewards for the project developers:
If congestion revenue is between the Cap and Floor, no adjustment is made
Congestion Revenue above the Cap is returned to consumers
Any shortfall of congestion revenue below the Floor requires payment from network users
The duration is 25 years with assessment periods of 5 years.
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Figure 28 : Revenues are “capped” at an upper limit
Downside losses are protected by the “floor” with consumer underwriting.
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1.4.9 Conclusions: Lessons learned from Europe for NAPSI
The EU Regulation allows 3 regimes for the interconnectors:
▪ the Regulated regime with possible EU complementary grants
▪ the Private Regime with exemption of regulated requirements
▪ the Hybrid regime: Cap and Floor for risk mitigation
Role of a Regional Regulatory Coordination is key for the success of the devel-
opment of electricity exchanges
Table 10 : Comparison between the regulatory coordination
of Europe, Africa and South America
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2 INVESTMENT COST RECOVERY
2.1 OBJECTIVES
The feed-In Tariff is the recommended methodology for stimulate the start of Renewable
Generations. The first part (§2.2) described the situation in Mongolia and the short term evo-
lution. Recommendations are presented for improving the Cost Recovery Methodologies and
the attractiveness of Mongolia for domestic and foreign investors.
The second part (§2.3) is related to Conventional Power. The experience of the large project
CHP5, that has eventually been abandoned, is described. The new policies and measures
up to 2030 are presented with the mid-term program. Recommendations are given for im-
proving the attractiveness of Mongolia for domestic and foreign investors since the financing
of new fossil-fuel project has been influenced by the Paris Agreement signed in 2015.
The third part (§2.4) presents the Cost Recovery Methodology for European interconnector
and Recommendations for organizing the NEA Power Trade on the same basis.
2.2 RENEWABLE ENERGY IN MONGOLIA
2.2.1 Introduction on the Mongolian Power System
One of the priorities of the state energy policy to provide reliable supply of firmly increasing
energy demand mentioned in the recent statistical report data. Presently, the energy system
is transforming from solely conventional coal-based energy generation into mix of conven-
tional and new energy generation technologies. Main role and objective of the energy system
managers is facilitation of reliable, sustainable and constant operation of such modern con-
ventional and new mixed technologies. The introduction of a new energy generation technol-
ogies into Mongolian energy system becoming important issue.
Presently the Mongolian energy system is subdivided into five energy subsystems due to
geography, climate and populations as shown in the figure below. All these energy systems
have own generation sources, energy demand and energy system operation regimes. The
consumers in these energy subsystems mostly provided by electric and heat energy pro-
duced by conventional generation based on coal burning thermal energy generation technol-
ogy which causes some negative impacts such as reduction of fossil fuel resource, ecologi-
cal damage and climatological changes Figure 2. As result the energy system faces chal-
lenge on introduction and wide scale adoption of new environmentally clean energy technol-
ogies.
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The renewable energy is unexhausted, clean, environmentally friendly energy generation
technology based on solar, wind, small hydro and geothermal energy.
Figure 29 : The Energy System of Mongolia
The installed capacity of the Mongolian energy system was 1,246 MWs, 84.2% of the
capacity is in CHP, 3.7% in Diesel, 12.1% in Renewables.
However, from the 7,602 mln. kWh consumed in 2017, 20.7% was imported.
CHPs generate 95.8% of total electricity while RE generated only 4.2% in 2017
Figure 30 : Installed electricity generating capacity by source
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By the end of 2019 RE capacity is expected to reach 21%
Peak demand is expected to reach1,388 MW in 2020, 2,600 MW in 2026, 3,470 MW
in 2030 and 4,338MW in 2036
Figure 31 : Mongolia existing Supply-Demand
As global community set targets to wide scale adoption and transition to clean, environmen-
tally friendly energy technologies the Government of Mongolia took certain firm actions to
introduce clean, environmentally friendly, sustainable energy technologies. The Parliament
of Mongolia has adopted new energy sector development policy along with amendment of
energy law and renewable energy law of Mongolia. Also, in 2014 the Parliament of Mongolia
adopted the new green development program. All these major legal documents targeted to
build favorable legal and financial environment for environmentally clean technologies. The
new policy documents set objective to increase share of renewable energy technology in
total installed capacity of the country to 20% by years of 2023 and to 30% by years of 2030
in comparison the share of renewable energy is 7.62% in base year of 2015.
With adoption, such legal documents several renewable energy technologies based project
have been implemented in Mongolia. The following project could be mentioned as example:
the 50MW Salkhit wind project (started commercial operation in 2013), the Darkhan 10MWp
solar power PV project (started commercial operation in January 2017), the 10MWp Mon-
naran solar power PV plant (scheduled to start commercial operation in mid-2017) and the
50MW Togttsetsii wind project (scheduled to start commercial operation in September 2017).
According to the data of Energy Regulatory Commission presently dozens of solar energy
projects under development. ERC estimates that 600-700 MW will be added on existing de-
mand by 2020, corresponding to the annual growth of 3.5% as shown in the Figure 3.
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Figure 32 : Future power demand in Mongolia
According to the most recent data published by National dispatching center of Mongolia the
share of renewable energy generation is about 7 percent in total energy generated in Mongo-
lia and it is expected to double by end of 2018. Increase of domestic renewable energy gen-
eration will lead to dramatic decrease of import power and in the future, it could facilitate
clean energy export not only to our neighboring countries but also to North East Asian coun-
tries.
2.2.2 Renewable Energy Projects
The renewable energy is one priority for the Mongolian energy sector, as set out by the Gov-
ernment in policy documents such as the Government Action Plan, Millennium Development
Goals and Mongolia’s Strategy for Sustainable Development of the Energy Sector 2002-10.
For the government, the use of renewable energy is vital for improving and securing a sus-
tainable energy supply, particularly for rural electrification and heat supply. It attaches great
importance to the research and exploitation of new energy sources. Nonetheless, power
supply scenarios reveal that renewable power will cover only a smaller portion of growing
demand. Some observers, are skeptic whether the high capacity renewable power plant can
be realized within a few years so as to completion of Egiin HPP.
According to new Updating Government Policy on Energy sector, presented to Parliament of
Mongolia by Ministry of Energy, share of renewable energy technologies in total energy sup-
ply 20% by 2020 and to 30% by 2030, that same with Renewable Energy Program adopted
by 9th Jun 2005.
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Figure 33 : New power sources to be installed by 2020
SOURCE : Ministry of Energy of Mongolia
Table 11 : New power sources to be installed by 2020
By new Updating Government Policy on Energy sector, described a new support for renewa-
ble energy development is to improve legal environment and creation of financing ways for
Renewable energy fund, through introduction tax from coal export earnings to this fund. And
also, it is described that, the great opportunity for renewable energy development consists in
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wide deployment of large capacity renewable power sources and export of the electric power
to the China and Northeast Asian countries.
Existing Renewables in Mongolia
By end of 2018 the total installed capacity of the Central region energy system will reach
1255.8MW from which 84.2% or 1065.8 MW will be thermal power plants and remaining
190MW will be wind and solar power plants.
Solar Farms:
Darkhan 10 MW
Monnaran 10 MW
Naranteeg 15MW
Sumber 10MW
Wind Farms:
Salkhit 50MW
Tsogt Tsetsii 50 MW
Sainshand 55 MW
Hydro Power Plants:
Taishir 11MW
Durgun 12 MW
Multiples small scale plants on rural regions
2.2.3 Investment and tariff
TSETSII WIND FARM CASE
Clean Energy Asia LLC, the Project Company, started operation of 50 MW wind farm in De-
cember 2017 and the award-winning project raised project finance of US $128 million
through debt and equity finance.
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Figure 34 : Tsetsii Wind farm description
Figure 35 : Tsetsii Wind Farm interest expense
The second wind farm in Mongolia is financed by the Japan International Cooperation Agen-
cy (JICA), as a JICA's first overseas investment and loan project in renewable energy sector,
and the European Bank for Reconstruction and Development (EBRD) through debt financing
arrangements. Whereas, Clean Energy Asia LLC is owned by Newcom LLC, a Mongolian
conglomerate with activities in telecommunications, property and energy and SB Energy
Corp.., a subsidiary of SoftBank Group Corp, the telecommunications and technology con-
glomerate in Japan.
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Figure 36 : Tsetsii Wind farm development cost
SOURCE: Renewable Energy Development in Mongolia by CEO of Clean Energy Asia LLC, Orchlon Enkhtsetseg, 2018
Figure 37 : Tsetsii Wind Farm Gearing
As result of implementation of the project, it is estimated that approximately 230,000 tons of
greenhouse gas emissions will be displaced and 180,000 tons of coal and 1.2 million tons of
water will be saved. In addition, production of electricity at the wind farm will overall help
reduce the amount of imported electricity. Located in southern Mongolia, the Project will con-
tribute further benefits in facilitating infrastructure development for railway, road and electrical
infrastructure at local and national levels.
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LICENCE
Energy Regulatory Commission (ERC) has the authority to issue, suspend and terminate
licenses, resolve certain types of disputes between license holders and consumers. Accord-
ing to the article 12 of Energy law the following licenses are issued to a legal entity by ERC.
1. Electricity generation
2. Heat generation;
3. Electricity transmission;
4. Heat transmission;
5. Dispatching;
6. Electricity distribution;
7. Heat distribution;
8. Regulated supply of energy;
9. Unregulated supply of energy;
10. Importation and exportation of electricity;
11. Construction of energy facilities;
12. Gas supply
Licenses for construction of power lines crossing the state borders and construction of ener-
gy facilities with capacity of over 5MW and dispatching licenses shall be issued by the Regu-
latory Commission upon permission of the State Central Administrative Authority.
Power plants equal to or lower than 1,5MW capacity are considered as own use and con-
struction of its transmission and distribution lines do not have any adverse impact on the en-
vironment and normal living conditions of people. Therefore, licenses shall not be required
for construction and operation of such power plants.
As of the six months of 2015, ERC has issued 203 licenses to 96 legal entities and been
monitoring compliance with these terms and requirements of the licenses issued.
Licenses issued for RE development
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Figure 38 : Current Solar, Wind and Hydro licenses in Mongolia
Figure 39 : Solar power plant license owners
SOURCE: RE Status of Mongolia by Chimeddorj. D, Head of Policy Planning Dept, MOE, 2018
Figure 40 : Wind, Hydro and Biomass power plant license owners
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TARIFF
Current Renewable Energy Price and Tariff
The Energy Regulatory Authority shall set tariffs of energy generated and delivered by a re-
newable energy power sources connected to the grid within the following limits:
US$ 0.08-0.95 per kWh of electricity generated and delivered by a wind power
source,
US$ 0.045-0.06 per kWh of electricity generated and delivered by a hydro power
plant with capacity of less than 5000 kW;
US$ 0.15-0.18 per kWh of electricity generated and delivered by a solar power
source.
The Regulatory Boards of aimags and capital city shall set tariffs of energy generated by
stand-alone power sources within the following limits:
US$ 0.10-0.15 per kWh of electricity by a wind power source
US$0.08-0.10 per kWh of electricity by a hydropower plant with capacity of less than
500 kW
US$0.05-0.06 per kWh of electricity by a hydropower plant with capacity of 501-2,000
kW
US$0.045-0.05 per kWh of electricity by a hydropower plant with capacity of 2,001-
5,000 kW
US$ 0.2-0.3 per kWh of electricity by a solar power source.
2.2.4 Further development
2.2.4.1 Renewable Energy Policies
The purpose of this law is to regulate relations concerning generation of power using renew-
able energy sources and its delivery.
In 2015, the Parliament of Mongolia set the country’s mid-to-long term targets in the energy
sector and its plan for 2015-2030. According to which, Mongolia aims to increase the share
of renewable energy generation in its annual energy production to 20% by 2020 and 30% by
2030. The project will contribute to the national power policy goals.
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Table 12 : Mongolia energy policy since 2001
Source: State Energy Policy, Renewable Energy Objectives
Table 13 : Mongolia Energy State Policy
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Table 14 : Renewable energy projects in Mongolian government plan (2016-2020)
2.2.4.2 Renewable Energy Law Amendment
Mongolia has first adopted a renewable energy act in 2007 (as amended from time to time)
(the "REL"). In April 2018 the Ministry of Energy of Mongolia has announced its plans to
amend the REL. Subsequently, on 30 Oct 2018, a bill proposing amendments to the REL has
been submitted to the Parliament of Mongolia (the "Bill"). The Bill has been introduced to the
Parliament and is being sponsored by several MPs, including Chairman of Economic Stand-
ing Committee.
1. The existing feed-in-tariffs (“FIT”) would be amended (reduced) as follows:
Table 15 : Current Feed-in-Tariffs (“FIT”)
2. Prospective power purchaser must submit evidence of availability of financing
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The MoE considers sur over-licensing as difficulties for the license holders in finding the
adequate funding. This situation cannot continue.
Therefore, under the Bill, any renewable power purchaser would need to submit to the Ener-
gy Regulatory Commission, Mongolia’s regulator, evidence (assurance) of availability of fi-nancing necessary to build, and to launch, the facilities to produce power.
3. Cost of building substations would be transferred from transmitter to power pro-
ducer
In practice, however, the transmitter, being a state-owned public utility, often lacks funds to
finance interconnection works, which usually include building/upgrading a transmission sub-
station. As a result, costs of building/upgrading the substation have in practice been borne by
the IPPs (or sometimes even financed through grants from MDBs).
4. MOE would competitively procure renewables
According to the Bill, it will be the MOE who will (i) adopt the procedures regulating the com-
petition and (ii) carry out the competition.
Presumably, (ii) above means that the MOE will act as the key party to, among others, an-
nounce the call for project proposals, lead the evaluation and eventually award the project.
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2.2.5 Recommendations the development of Renewable Energies in Mongolia
Recommendations for improving the Cost Recovery Methodologies and the attractiveness
of Mongolia for domestic and foreign investors are the followings:
Give enough visibility on the renewable energy policy targets and market vol-
ume:
Foreign investors would come to a new country if they see a sufficient volume of pro-
jects they can invest in for the long term. The visibility horizon should be at least 10
years on Energy Policy with good level of monitoring by the Government,
Ensure foreseeable and stable Revenues:
• Renewable energy projects need some clarity on the long term electricity price and on
the electricity market mechanisms. Investors require foreseeable and guaranteed rev-
enues. The same for the taxes.
• In case of Feed in Tariff: the calculation should allow extra revenue in case better per-
formance than expected.
Guaranty the Grid Operation: Priority dispatch / no curtailment:
Clean energy is intermittent but needs to be able to inject when wind is blowing or sun
is shining. Moreover, procedure of compensation have to be clear and guaranteed in
case of Grid failure.
Guaranty the Grid connection with enough capacity on short and long runs
Improve the Contractual and Legal maturity:
The legal context in which renewable projects will be built needs clarity and stability
(clear and stable frame for permitting, sale of electricity, tax, etc…).
Develop adequate Financing facilities:
• Renewable energy projects are very CAPEX intensive. It is crucial that financing insti-
tution feel comfortable in financing renewable projects.
• Recommended Fixed Interest Rates and no exchange rate risk. Long term debt com-
pliant with Tariff period of guaranty, Gearing at least of 80%,
Get reliable pre-permitted sites
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2.3 CONVENTIONAL POWER
2.3.1 Experience of CHP5
2.3.1.1 Project Development Milestones
May 2011 – Feasibility Study of CHP5 Project was developed initially by H&J and Mon-
Energy Consult LLC under the Technical assistance provided by the ADB and delivered
to Ministry of Energy. It was planned to be built next to CHP 3.
February 21, 2012- the Government of Mongolia (GoM), SPC has provided RfP of CHP5
Project to short-listed bidders.
May 7, 2012 - bidders have submitted their technical and financial proposal to the State
Property Committee.
July 5, 2012 - the GoM informed that the Consortium (GDF Suez, Sojitz, Posco Energy
and Newcom) was selected as preferred bidder.
October 19, 2012 - the GoM decided to change the location of the project.
December 22, 2012 - the GoM has issued resolution # 191 with 5 clauses and decided to
relocate the project site at Khuliin river valley located in territory of 11th khoroo of Bayan-
zurkh district of Ulaanbaatar city.
April 2013 – Consortium submitted Best and Final Offer to the Ministry of Economic De-
velopment and was selected as a preferred bidder.
July 2015 - The updated feasibility study was approved by the Science and Technologi-
cal Committee of the Ministry of Energy. Due to site change Consortium conducted 7
additional studies for Feasibility Study.
2.3.1.2 Project Site
CHP5 was relocated about 15 km southeast of UB, on a Greenfield site within the Khulin
valley.
Figure 41 : CPH5 project site
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Past Status of the project:
ESIA and DEIA was completed.
Concession Agreement was signed with GoM on 20 June 2014.
PPA was signed on 29 July.
CSA, HPA, WUA, LUA - agreement is 50-90% complete
EPC contract - 98%
Financial closure – March 2017
Earthwork at the project site – April 2017
Unit I and II – 2021 and Unit III in 2022
2.3.1.3 Project Needs
The current CHPs are outdated with decreasing efficiency.
CHP2 – 45 years;
CHP 3- 48 years;
CHP4 – 33 years;
Darkhan CHP – 51 years;
Erdenet CHP – 29 years
The Technical and Economic Feasibility Study of 2013 and the renewed plan “General Plan to Develop Energy Sector” (Master Plan) highlighted the importance of establishing a new reliable energy source to ensure meet the increasing electricity and heat demand and ensure
the stability of the Mongolian economic development.
The Parliament Policy Document, approved as of 2016, prioritized the importance of con-
structing the 5th energy source with a built capacity to supply electricity and heat which
solves electricity and heat demand in environmentally friendly way that uses advanced tech-
nology, increase efficiency and reduces the carbon dioxide emission.
The Consortium of ENGIE (GDF Suez), Sojitz, POSCO, and Newcom is considered by MOE
as the best reliable investors, with many years’ of experience in developing, constructing,
and operating an independent power station design and layout.
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2.3.1.4 CHP-5 Tariff and Increase of CES Tariff
In case of CHP-5 project, the tariff will be increased by 1% per year between 2021 –
2045
Starting from 2032, End-user tariff of the electricity produced by CHP-5 will be cheaper
than the end-user tariff of CES when such tariff is considered to be increased by 6% an-
nually. Therefore, CHP-5 acts as main power plant producing electricity with stable price
for longer term in the future.
For last 20 years between 1996 and 2015, CES tariff has increased by 12% annually.
For last 15 years between 2000 and 2015, CES tariff has increased by 9% annually.
For the forecast of end-user tariff, we considered the average increase between 2016
and 2045 as 6%.
Figure 42 : CHP5 Tariff History and Forecast
2.3.1.5 Project Structure
The project company, CHP5 LLC, has been incorporated in September 2012
Engie, Sojitz, and POSCO Energy to initially hold roles of CEO, CFO and COO respec-
tively. To be rotated between Sponsors
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Figure 43 : CHP5 Project Structure
2.3.1.6 The Consortium disbandment
A meeting was organized on April 19th, 2016 at the Ministry of Energy ("MOE") between the
MOE, the Concessionaire, the Concessionaire's lenders (and their legal advisors) and the
Government's transaction advisors. During that meeting, the MOE emphasized to the Con-
cessionaire and Concessionaire's lenders the importance of finalizing the outstanding issues
on the CHP5 project agreements and starting the construction of the CHP5 Project as soon
as possible.
In particular, the Concessionaire proposed that the final CHP5 project agreements should be
signed in June 2016. In order to achieve that objective, the Concessionaire respectfully re-
quests Invest Mongolia to confirm:
The proposed exact date (in June 2016) for the signing of all CHP5 project agreements
(the Signing Date), and
Commitment of the Government of Mongolia to mobilize all necessary resources to
achieve the signing of all CHP5 project agreements by such Signing Date.
In that regard, the Concessionaire required the conditions to be fulfilled, before the signing
date, so that the Concessionaire is in a position to sign the CHP5 agreements.
As no positive answer was given, the Consortium was disbanded.
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2.3.1.7 Requirements to be fulfilled prior to Signing Date
Table 16 : CHP5 – Requirements to be fulfilled prior to Signing Date
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2.3.2 Upgrade in Conventional Power Project
2.3.2.1 National Energy Policy Mid-term Implementation Program (2018-
2023)
The following program identifies measures to be implemented under resolution 63 “Govern-ment Policy on Energy” approved by the Parliament of Mongolia on the 19 day of June of
2015.
The mid-term program shall comprise measures to be undertaken in accordance with the
State Energy Policy strategy and shall include information regarding the required budget,
financial estimation, source of funding and criteria for assessing program outcomes.
Increase Darkhan CHP’s installed capacity by 35 MW;
Renovate and renew turbine generators (No 1-4) at CHP4;
Increase Erdenet CHP’s installed capacity by 35 MW;
Increase Choibalsan CHP’s installed capacity by 50 MW;
Increase CHP3’s installed capacity in the high pressure area by 75 MW;
Expand Amgalan TPP in to a CHP with an installed capacity of 50 MW;
Expand Ulaanbaatar CHP3 with 250MW;
Expand CHP 2 with 300MW installed capacity;
Build a CHP based on Tavan Tolgoi coal mine to supply energy to Oyutolgoi.
Start to study technical solutions to safely incorporate Baganuur 700MW, Buuruljuutiin
300 MW CHP projects into the central system to meet increased central regional energy
demand;
Start the development of an energy source no less than 100 MW in Altai-Uliastai energy
system;
Start the development of a CHP reliant on coal resources of the Western 5 aimags.
2.3.2.2 Policies and Measures for Implementation up to 2030
Reduce internal energy use of Combined Heat and Power plants (improved plant effi-
ciency) from 14.4% in 2014 to 11.2% by 2020 and 9.14% by 2030
Implement advanced technology in energy production such as super critical pressure
coal combustion technology by 2030.
Reduce electricity transmission losses from 13.7% in 2014 to 10.8% by 2020 and to 7.8%
by 2030.
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Reduce building heat loss by 20% by 2020 and by 40% by 2030, compared to 2014 lev-
els
Increase RE capacity from 7.62% in 2014 to 30% by 2030 as a share of total electricity
generation capacity.
2.3.2.3 Convectional Generation GHG Emission
The INDC of Mongolia includes proposed measures and additional actions for energy (including
transport), industrial processes, agriculture and waste. Projected emissions by sector for 2010 and
2030.
Figure 44 : GHG emissions share by sector in 2010 and 2030
(Forecast, excluding LULUCF)
Convectional generation increase x 3 times
Table 17 : Mongolia energy development 2010-2030
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2.3.3 Recommendations for new Conventional Power in Mongolia
There is a global new deal for coal after the signature of Paris agreement in
2015: only some lenders still may provide financing for coal-fired Power Plants.
Hybrid Electricity + Heat may still be possible by Western financing as long as
it contributes only to stabilize the output of renewable generation.
The same recommendation of the § 2.2.5 are applicable for improving the at-
tractiveness of Mongolia for domestic and foreign investors.
2.4 INTERCONNECTIONS
2.4.1 Notion of Economic Congestion Rent
The need of a new interconnection can be measured by the difference of market prices of the
2 zones that could be interconnected.
The economic congestion rent is the price differential between two price zones times the
volume of transmitted electricity. Congestion rent is an indication of insufficient interconnec-
tion capacity between zones. When there is sufficient capacity between two zones, the prices
converge and thus rent disappears.
Figure 45 : Definition of the Economic Congestion Rent
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2.4.2 Notion of interconnection benefit
When a new Interconnection is built between the 2 TSOs A&B or price zone the benefit can
exceed A&B and can spread of other TSOs that are interconnected to A&B. Especially when
the TSOs are interconnected according to a ring as described in the following figure.
Figure 46 : New interconnector that is part of a ring
The benefits of a new interconnection has to be estimated from the customer perspective. All
the transmission costs have to be paid by the importing country.
2.4.3 Transmission Tariffs
Many methodologies are used in the world for designing the Transmission Tariffs. They be-
long to 3 large families: Postage Stamp, Distance based and Nodal Price.
Postage Stamp
This method, like the postal service, is based on average costs and is not related to the dis-
tance neither does it distinguish between the entry and exit points. This method allocates a
uniform transmission tariff to all transmission customers, irrespective of the load imposed or
congestion created by the network user.
This is a very simple method very easy to compute and simple to understand since each
network user pays the same tariff.
The formula can comprises Capacity (MW) or Energy (MWh) values or both.
The parameters of the formula can to be adjusted to cover the transmission costs of the
TSO.
However, the method is not related to physical flows and is irrespective of System operation
costs per power flow.
Distance based: MW - kilometer
The MW-Kilometer method (Distance-based) allocates the transmission wheeling charges
based on the transmission capacity and the wheeling distance. This distance based method
uses for specific transaction calculation:
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Point to point according of the lines that are used ۔
More complex Power flow calculations associated to the used assets for the possible ۔
path as well as the energy and capacity flows with the length of lines and the network
costs of these lines.
As it is related to physical flows, it is very simple and easy to understand.
Nodal Price
Nodal pricing takes into consideration each origin and destination of the exchanges of elec-
tricity. Therefore, each node has its own price. This pricing philosophy is justified on the
grounds of locational economic signals, since the transmission prices are determined to re-
flect the costs imposed on the system by the transaction. The prices are set based on the
marginal impact on the system of a new transaction and takes into account all aspects in-
cluding System capital & operation cost. The prices moves in real time.
The calculations are complex and realized by computers with dedicated software. The results
are more difficult to understand and the methodology may appear as a “Black Box”.
2.4.4 Questionable relevance of Transmission Tariffs regarding the cost recovery of interconnectors
When Transmission tariff is added to low prices electricity dedicated for exportation, the risk
is that the total price Generation + Transmission may exceed the price of the country of ex-
portation and, consequently, appears to be not cost effective in the importing country
The figure illustrates the 2 situations that may occur:
in green, total price Generation + Transmission is below the System marginal price of the
importing country (P2). In this case, the exportation is cost effective and will be accepted
by the Market of the importing country
in red, total price Generation + Transmission exceed the System marginal price of the
importing country (P2). In this case, the exportation is not cost effective and will not be
accepted by the Market of the importing country
And this is the main problem for Mongolia because even if Solar and Wind Energies pro-
duced in Mongolia are the most competitive of the region, the gap with some other countries
especially with China is not so important. Consequently, if Mongolian clean energies bear
important Transmission cost in addition, they will not be cost effective in the countries when
they are imported.
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Figure 47 : « Cap and Floor » principle.
TT : Transmission Tariff
2.4.5 General recommendations for Cost Recovery Methodologies
2 principles for the interconnector cost recovery methodology are recommended, inspired
from the European experience. The design of the cost recovery methodology should be de-
signed:
1. With market based solutions which gives appropriate price signal to the market par-
ties and TSOs involved
2. With non-discriminatory methods that do not involve a selection between the con-
tracts of individual market parties
3 basic methodologies can be used:
Regulated between 2 TSOs
Merchant by Private Sector
Hybrid (Regulated + Private) for Risk Mitigation
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2.4.6 Congestion management Methodologies
There are 3 main standards in the world for congestion management:
Explicit auctions for Transmission rights
Implicit auctions for Transmission rights also called market splitting.
Counter Trading / Re-dispatching
Explicit Auctions The difference in price between the two countries corresponds to the “economic congestion rent” available from the use of the interconnector.
Both TSOs A&B organize the (explicit) auctions of the transmission rights into 2 separate
markets.
Assuming that the System marginal price of A is lower than B, all the generators in country A
will be keen to bid for access to the Country B market.
The most likely outcome, therefore, is that capacity in the interconnector is bid up to a
price close to the “economic congestion rent” TSO A and TSO B sell the Transmission Rights to the generators and the best price of all
generators in country A wins.
With the explicit auctions, the economic rents available will tend to be collected by TSO A
and TSO B. Some price reductions of electricity in country B due to competition will benefit
the customers. No economic congestion rents are available to generators.
Implicit Auctions / Market Splitting
Under implicit auctions, there is only one combined market A&B.
TSO A + TSO B working together knows all the generation prices and the interconnection
limitation and makes the decisions by themselves based on economic precedence.
The TSO fixes the price for using the interconnector on the basis of a comparison of electrici-
ty prices offered by the generators. Each generator in both countries nominates an amount it
wishes to supply into the combined A&B market and the lowest price it is willing to offer elec-
tricity into the market.
First, the TSO A + TSO B calculates the system price that would prevail under unlimited
Interconnector capacity.
Then, the TSO A + TSO B recalculates the price in each market taking into account the in-
terconnector and its constraints.
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TSO A + TSO B knowing the details of all prices offered can calculate exactly the required
surcharge. The TSO levies a surcharge on the prices offered by generators in Country A who
wish to sell in Country B such that enough of these bids are priced out of the market.
With the implicit auctions (as well for the explicit auctions, the economic rents available will
tend to be collected by TSO A and TSO B. Some price reductions of electricity in country B
due to competition will benefit the customers. No economic congestion rents are available to
generators.
Counter Trading / Re-dispatching As under implicit auctions, there is only one combined market A&B.
TSO A + TSO B working together knows all the generation prices and the interconnection
limitation and makes the decisions by themselves based on economic precedence.
The differences is that the TSO A + TSO B bares the cost of re-dispatching to due to the
congestion: the TSO A + TSO B uses their balancing markets to comply with the demand-
supply.
There are no bids but the TSO A + TSO B must then assess the extent to which the nomina-
tions of generators are in excess of the available capacity of the interconnection and decide,
on some basis, which generators would be constrained.
Under counter trading all economic rents are passed to customers in the high cost country.
Instead of collecting rents, the TSO suffers costs as a result of the constraint. This gives a
clear economic signal to the TSO about the seriousness of the constraint. High constraint
costs are a signal to upgrade the network.
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2.4.7 Recommendations for the organization of the NEA Power Trade
2.4.7.1 Interconnector financing
Based on the previous approaches, the recommendation for the Interconnectors Financing
are the followings:
The preferred method is to finance the interconnectors by the 2 TSOs according to the
regulated regime
Letting the option open for partial or full financing by the private sector
The Regulatory Coordination should provide additional grants to complete the financing
in compensation of the economic benefit for other TSOs
2.4.7.2 Interconnector Cost Recovery
Based on the previous approaches, the recommendation for the Interconnectors is to recover
the cost through Transmission Right Auctions reserving:
Explicit auctions for long term: from yearly to weekly
Implicit auctions for short term: Day Ahead
In real time, the remaining capacities should be handled by the TSO’s through their own bal-
ancing markets.
Figure 48 : Recommended principle for interconnector cost recovery
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This methodology guarantees that exported low price energy will remain cost-effective in the
importing country independently from the cost of the interconnection.
The basic reason of the efficiency of this methodology that is used in Europe is separation
between 2 businesses:
The Interconnection service with dedicated costs & revenues
The Generation and Exchange of electricity between countries
This methodology ensures that no Transmission costs will be added to generation cost and
this is very important for the cost effectiveness of the Solar and Wind electricity produced in
Mongolia.
This principle guaranties free access to other national markets to the most cost effective
electric.
This methodology is illustrated by the following figure.
Figure 49 : Illustration of the recommended principle for interconnector cost recovery
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2.4.7.3 Regulation requirements
The recommendations are made at 2 different levels, national (for each countries) and re-
gional (Northeast Asia):
At national level, the Regulations of Russia, Japan, Republic of Korea, China and
Mongolia should be modified in the following domains :
1. Third Party Access (TPA): Transparent and non-discriminatory access to inter-
connection should to be guaranteed for all players especially IPP
2. Creation (if does not exist) and guaranty of independence of National Regulatory
Authorities
3. Guaranty of independence of TSOs (encouraged by policies)
4. Creation of a Balancing market allowing the TSO to handle the variations of de-
mand- supply with reserve capacities and energy volumes offered by the national
markets
5. Market operator should be designated: it can be the TSO or a separate entity
At regional level, the Regulations of Russia, Japan, Republic of Korea, China and
Mongolia should be harmonized in the following domains :
1. The mission given to the National Regulatory Authorities (NRAs)
2. Free regional market should be ensured for all players
3. Power trade contracts should be standardized
4. Competitive mechanisms should be institutionalized
5. A Regional Grid Code should be built for sharing clear common rules
6. Comprehensive methodology for selling the transmission rights of the intercon-
nectors
7. Same priority for domestic demand and export commitments should be agreed
with sanction agreement in case of non-respect.
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2.5 MONGOLIA GRID UPGRADE
2.5.1 Objectives
Following the Module 5 report on Power System Interconnection, the Mongolian grid should
be upgraded in 500kV HVAC as described in the following figure.
Figure 50 : Recommended Mongolia grid upgrade from Module 5 report
The recommendation for the financing and the cost recovery of the upgraded grid of Mongo-
lia is to consider it as an interconnection. With two options:
- Considered as a regional interconnection
- Considered as interconnection between Russia and China
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2.5.2 Recommendation option N°1: the new 500kV grid in Mongolia is considered as part of the NEA interconnection
The recommendations for the Project financing and management are the followings:
The project should managed as a Build Own Operate and Transfer (BOOT)
Built by the owners: the NEA TSOs
Operated by Mongolia TSO: today, the National Dispatch Center (NDC) and the
transmission company Transco which are today parts of the Ministry of Energy of
Mongolia
Transferred to Mongolia after an operation period. Proposed period as a basis for
discussions: 20 years
The Market Operator is the NEA TSOs Consortium
The recommendations for cost recovery are the same as described § 2.4.18 through Trans-
mission Right Auctions with:
Explicit auctions for long term: from yearly to weekly
Implicit auctions for short term: Day Ahead
In real time, the remaining capacities should be handled by the balancing markets.
2.5.2.1 Recommendation option N°2: the new 500kV grid in Mongolia is con-
sidered as an interconnection between Russia and China
The recommendations for the Project financing and management are the followings:
The project should managed as a Build Own Operate and Transfer (BOOT)
Built by the owners: the Russian and Chinese TSOs2
Operated by Mongolia TSO: today, the National Dispatch Center (NDC) and the
transmission company Transco which are today parts of the Ministry of Energy of
Mongolia
Transferred to Mongolia after an operation period. Proposed period as a basis for
discussions: 20 years
The Market Operator is the tripartite consortium composed of the Mongolian, Russian
and Chinese TSOs Consortium
The recommendations for cost recovery are the same as described § 2.4.18 through Trans-
mission Right Auctions with:
Explicit auctions for long term: from yearly to weekly
Implicit auctions for short term: Day Ahead
In real time, the remaining capacities should be handled by the balancing markets.
2 Options could be part the existing regional strategic cooperation framework or promising cooperative intention, like the Belt-
Road Initiative or China-Korea agreement on Grid interconnection cooperation and etc. An opportunity for NAPSI to reach
consensus with more NEA governments and to expand the bilateral cooperation to three or more parties including Mongolia.
Joint efforts of governments are the key point to achieve cross-boundary grid interconnection.
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3 REGULATION FRAMEWORK AT REGIONAL LEVEL: THE
NAPSI AUTHORITY
It is essential to organize a coordination at regional level of the National Regulatory Authori-
ties. The recommendations are made for 2 time horizons: at first step and as target.
First Step : a strong regional coordination among the 5 Regulators should be es-
tablished
After a phase of dialogue to be established among the 5 Regulators, as for instance the Fo-
rum of Florence in Europe, an organization should be established with a name and charter
for easy identification and then first common set of rules for working together.
As target : a dedicated regional common NAPSI Entity for managing the NEA Inter-
connections should be established for
1. Regulation monitoring
2. Infrastructure Project Financing
3. Cost recovery methodologies
4. Operation & Maintenance including feedback / lessons learned
5. Common rules implementation & Control
It is important that all the countries share the same rules: recommendations for a NAPSI Grid
Code are presented. This NAPSI Platform Body is a paradigm for ruling and managing the electrical interconnec-tion and Power Trade among the 5 countries. Here are the main fields of activities that could be developed in further studies: Regulation to be implemented at regional level and the follow-up of the necessary evolu-
tions and harmonization of the National regulations
Organization and governance
Proposal of a business plan to ensure the self-financing of the authorities through a con-tribution to be paid by the power generation companies and a fee paid by the transmis-sion company
Design of the concession scheme for the power generation companies and tendering process
Interconnector Project management from the design, pre-feasibility, feasibility specifica-tion, tender to the construction and commissioning
Maintenance : policies, operation data analysis and management, staffing , lessons learned from operation
Operation : real time supervision with dedicated load dispatch center, preparation of maintenance yearly, monthly, weekly daily, O&M data quality, IT and telecommunications
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4 FINANCING THE ENERGY SECTOR IN MONGOLIA
4.1 OBJECTIVES
The main objective is to assess the appetite of the international financial institutions regard-ing the financing of the energy sector of Mongolia, more precisely: • Define a typology of potential investors that may be the ones having interest for invest-
ment in renewable infrastructure, those in Mongolia but also out of Mongolia. • Highlight the categories of investors that have been investing in large scale projects in
Mongolia through relevant case studies. • Evaluate the appetite of a selected pool of existing investors having a presence in Mon-
golia in order to assess their potential interest in investing in one of the NAPSI projects through a bottom up approach.
Different case studies are illustrating the diagnostics and recommendations.
4.2 TYPE OF INVESTMENTS TO BE CONSIDERED
The NAPSI projects will consist in 2 categories of infrastructures: (1) the development of a
renewable energy capacity supplemented by coal fired power plants to balance the downtime
of the wind farms (2) the development of a grid.
Figure 51 : 4 main types of projects to be financed
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4.3 INVESTMENT ENVIRONMENT, INTERNATIONAL FRAMEWORK
Mongolia constantly proves itself to be in a global market. Mongolia is persistently discussing
to enter bilateral and multilateral agreements and actively participates in the process of re-
gional integration, As of now, Mongolia has established Foreign Investment Protection and
Promotion Agreement with 43 countries and Double Taxation treaties with 30 countries.
Moreover, Mongolia is member of the Seoul Convention establishing the Multilateral Invest-
ment Guarantee Agency and Washington convention on the Settlement of Investment Dis-
putes.
Consequently, in April 2014, Mongolia has introduced its investment policy and the law to UN
Conference on Trade and Development /UNCTAD/ releasing "Mongolian Foreign Investment
Policy Review. The overall feedback was positive, followed by recommendations and sug-
gestions towards the Government of Mongolia. The main concern that UNCTAD was having
is resource curse, followed which the recommendations were made. Firstly, to avoid macroe-
conomic instability, the Government of Mongolia has to determine new objectives and tools
of a comprehensive FDI strategy. Secondly, necessity for new regulatory and institutional
reforms for foreign and local private sector development. And lastly, Mongolia should devel-
op programs for achieving diversification through FDI and other activities of foreign compa-
nies.
Following in September, 2014, the second review of the trade policies and practices of Mon-
golia took place, where the basis for the review was a report by WTO Secretariat and a re-
port by the Government of Mongolia. The reviews were the similar to the UNCTAD's, which
again reinforced the importance of establishing a comprehensive FDI strategy.
In the year of 2015, Mongolia has completed Mongolia-Japan Economic Partnership Agree-
ment /EPA/ negotiations, which became the Foreign Trade Agreement of Mongolia. As any
other EPA agreement, Mongolia-Japan EPA has created an open door to both markets,
which eventually increase the competitive index of Mongolia and the FDI with the increase of
import and export between two countries, Therefore, Mongolia has mode another step to
become a big player in the global market.
Analyzing the overall performance of Mongolia on a global level, international indexes of dif-
ferent type have shown following results:
According to Forbes Magazine's "Ease of Doing Business report" Mongolia ranked 63
out of 146 economies.
According to the 2017 Doing Business report by the World Bank, Mongolia ranked 64
out of 190 economies.
According to "Index of Economic Freedom" by the Heritage Foundation, Mongolia has
gained overall score of 59.4 percent out hundred, losing in the categories such as
property rights and corruption.
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Figure 52 : Mongolia’s agreement with foreign countries
4.4 THE TYPOLOGY OF INVESTORS
There are mostly 4 categories of investors investing in such infrastructures:
The multilateral and bilateral Financial Institutions
The Government financing
The Private Sector Equity Investment
The Private Lenders
4.4.1 The multilateral and bilateral Financial Institutions
Those includes international financial institutions as ADB, AIIB, EBRD, IFC,.., as well as the
ones supported by single countries as DEG, FMO, Proparco, JICA, KOICA,… They propose financial solutions that are competitive in the market including grants, preferred interest
loans, and can invest in equity. They also provide the benefit of technical support in some
cases thanks to the expertise they have acquired in similar markets and similar projects.
Some of those multilateral and bilateral financial institutions are quite active in Mongolia, with
for instance:
The Asian Development Bank (ADB) has been Mongolia’s largest multilateral development
partner since 1991, approving assistance totaling US $1.92 billion over 24 years. Cumulative
disbursements for lending and grants financed by ordinary capital resources, the Asian De-
velopment Fund, and other special funds have amounted to US $1.1 billion. In 2015, the
ADB increased its commitment in Mongolia with new approvals totaling US $297.5 million,
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focusing on job creation, social protection, and climate change. To prevent cuts to welfare
programs, the ADB has also backed a US $150 million Social Welfare Support Program.
Additional financing of US $50 million was approved for an Agriculture and Rural Develop-
ment Project and $60 million for a Credit Guarantee Support Project.
Mongolia became a member of the World Bank Group (WB) in February 1991. The World
Bank has since provided US $808.17 million to Mongolia. As of April 2016, its portfolio in
Mongolia had total commitments of US $188.14 million, composed of 8 operations financed
by IDA credits totaling US $163.45 million and 12 trust funds totaling US $24.69 million. The
majority of World Bank projects support infrastructure development, economic governance
and institutional strengthening of the mining sector. In addition to the lending and grant oper-
ations, the World Bank also provides analytical and advisory work to Mongolia to support its
medium and long term development objectives and capacity building to implement the Gov-
ernment’s reform strategy in key areas.
The International Finance Corporation (IFC) opened its office in Ulaanbaatar in 1997.
Since then IFC has invested and mobilized more than US $818 million. IFC’s strategy in Mongolia is close to the EBRD’s; it invests in Mongolian financial institutions, particularly banks, to expand their services and access to finance for SMEs. IFC promotes international
corporate-governance and environmental and social standards, and invests in essential in-
frastructure, such as renewable power, telecom, and middle-income housing. It also supports
world-class sustainable mining projects to bring global financing, international technology,
and best environmental practices to Mongolia. IFC is working with partners across the mining
sector to raise awareness and standards on water management in the South Gobi desert.
IFC also invests in agribusiness and supports long-term reform to promote food safety
standards and competitiveness.
The Japan International Cooperation Agency (JICA)’s Mongolia Office was established in 1997. JICA has dispatched over 620 volunteers to Mongolia since 1992 and more than 4000
technical trainees to Japan. JICA is Mongolia’s most important bilateral donor, providing long-term sovereign loans in excess of US$ 500 million. JICA’s policy is for the Government of Mongolia to achieve a National Development Plan through 3 target categories, with 5 de-
velopment sectors. This policy was based on the new Directions of the Assistance of Mongo-
lia, launched in April 2012 by the Government of Japan. Priority areas of assistance include:
1) sustainable development in the mineral resource sector and stronger governance, 2) sup-
port for inclusive growth, and 3) enhancement of the capacity and function of Ulaanbaatar as
an urban center.
In 1997, European Investment Bank (EIB), the European Union's long-term financing insti-
tution, and Mongolia concluded the Framework Agreement under which the Bank conducts
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its financing and capital investment in the country. Since 2014, the EIB has invested around
€50 million to date. The bank has primarily focused on financing transport, water sewage and energy infrastructure projects under an investment program in the Ger areas of Ulaanbaatar.
The EIB is also preparing to sponsor an onshore wind farm near Sainshand. Since 2006,
Mongolia has been eligible to receive European Commission development assistance. The
Partnership and Cooperation Agreement signed in 2013 between the EU and Mongolia out-
lines and deepens their cooperation in trade, development, agriculture, and energy, which
materialized in €85 million in grants for the period 2014-2020. Part of that includes a €9.3 million SME development program, a comprehensive program implemented by the EBRD to
support SMEs, ranging from small consultancy to first loss guarantees to mitigate risk when
co-financing with local commercial banks. Among the most recent engagements are Trade
Related Assistance (TRAM) aimed at enhancing economic diversification and the Economic
Growth for Equitable Growth project.
The EBRD: a strong involvement in Mongolia
Grant funded technical cooperation (TC) in Mongolia has allowed the Bank to undertake a
preparation support program, including the preparation of infrastructure investment opportu-
nities, building capacities of prospective clients, and regulatory and judicial capacity building.
TC funds have also been provided to support the transfer of skills and the growth of local
private MSMEs, including through local and international consultants under the Advice for
Small Businesses, which is part of the Small Business Initiative. Mongolia has also benefited
from co-investment grants in the form of financial incentives and first loss cover in the sus-
tainable energy and financial sectors. These grants have been financed by multilateral funds
for climate change and multi-donor special funds.
The focus of donor grants is expected to remain in line with previous support. A 2017 grant
needs analysis in Mongolia shows the highest demand for the support of municipal and envi-
ronment infrastructure projects, capacity building related to green economy transition and
technical assistance to improve judicial and regulatory systems.
To sustain these needs, the EBRD will rely on a number of donor funds administered by the
Bank or managed externally, in addition to resources made available by its shareholders:
Bilateral grants – the EBRD will continue to explore opportunities with bilateral do-
nors, both through the EBRD multi-donor funds such as the Early Transition Coun-
tries Fund, as well as bilateral funds.
The European Union – the EBRD will also continue to partner with the EU and seek
funding from instruments that can be applied in Mongolia, including working closely
with the local EU delegation.
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The EBRD Shareholder Special Fund (SSF) - endowed by the Bank’s net income. The SSF is a complementary facility to donor resources and will provide TC and non-
TC support in areas where there is shortage or lack of support, however the area re-
mains a priority for the Bank to advance transition.
Illustrative case study : Energy Development Corporation in the Philippines
“when the multilateral becomes a shareholder”
EDC is an integrated geothermal steam and electric power producer in the Philippines and a
global geothermal energy industry leader. It is the Philippines’ largest vertically-integrated
geothermal developer, with an installed geothermal power generation capacity of
1,457.8 MW in the country.
Table 18 : EDC in the Philippines renewable energy sector
Energy Development Corporation (EDC) and the International Finance Corporation (IFC), a
member of the World Bank Group, signed a 15-year financing agreement for an amount in
Philippine pesos equivalent to USD 90 million. The proceeds of the loan will fund a portion of
the 2018 capital requirements and other general corporate purposes of EDC’s existing geo-thermal operations.
IFC will provide EDC a fixed-rate, long-term local currency financing. This, it said, will be third
time the World Bank unit will be doing so for EDC.
IFC invested in EDC some $49 million during its initial public offering (IPO) in 2006. In 2008,
IFC extended to EDC $86 million in long-term commercial loan, acting as a minority investor
and a lender
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4.4.2 The Government financing
On infrastructure project, the participation of the government provides a long term stability to
the other investors. Government can provide equity financing through its sovereign fund(s) or
asset holding, subsidies and loans are preferred conditions Government also help in provid-
ing some guarantees by the appropriate regulatory framework and potential guarantees to
the investors.
Sovereign wealth funds and other investors have been investing in several coal mining oper-
ations in Mongolia such as in companies as Tavan Tolgoi contributing to the best use of its
mineral revenues. The estimated value of the mineral deposits is a bit greater than US$ 1
trillion. The Government of Mongolia is trying to figure out a way to best serve its citizens.
Dutch disease can be a curse and crush ailing industries. The Government has publicly stat-
ed it wishes to avert that scenario.
Erdenes Mongol LLC was established in 2007 to implement government representation
into strategic assets as Erdenes Oyu Tolgoi LLC, Erdenes Tavan Tolgoi JSC, Baganuur
JSC, Shivee Ovoo JSC, and its subsidiaries.
Erdenes Mongol LLC's mission is to become a national investment company which en-
sures sustainable economic growth while managing Mongolian natural resources effec-
tively, making long term investments on mining, infrastructure, and energy sectors, in-
creasing business value, and delivering true returns to all shareholder citizens.
Investment Strategy of Erdenes Mongol LLC
To make long-term, quality investments in accordance with globally accepted stand-
ards through leading technology.
To manage reserves wisely and will ensure growth while generating reliable financial
resources.
To introduce and develop a comprehensive management system, designed to im-
prove competitiveness of our subsidiaries and associated companies.
4.4.3 The Private Sector equity investment
It may come from strategic investors which are international leaders in their own field as
for example companies as EDF, Engie, Kepco, Softbank, Datang…, with or without the
involvement of local companies. It may be large infrastructure funds specialized in the
sector as Macquarie, Brookfield, Global Infrastructures Partners, or IFM investors for in-
stance and eventually hedge funds. Expected returns are generally higher and whether a
strategic partner can, bring an expertise, the addition of an infrastructure fund may help
to contribute to limit the financial risk from the strategic investor.
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Case study 1: Strategic Partnership - Conventional Energy based on USCF Power
Plant invested by EDF
Summary of the project: a Joint-Venture Company to build and operate a 2X1000MW
Ultra-Super-Critical Coal-Fired Power Plant with a Partner in east-northern district of the
Province, China
Key outputs: A dedicated railway was to be in operation in October 2013; it will be a ma-
jor railway transportation line for coal supply to USCF project (Domestic and international
coal supply). Increase power capacity and promote the installation of eco-friendly coal-
fired power generation. The dispatch hours is composed of 5000h as provincial basic
dispatch and 200h as high efficiency power plant bonus for the first 10 years
Investment required: Total =Investment in the power plant which amounts to RMB
7,228 million, including:
Construction costs: consistent with the standard construction cost for 1000 MW
ultra-supercritical units in China.
Interest during construction.
Owner's costs: including project company management costs, pre-operating
costs, costs associated to land use right, insurance, coal stock, etc.
D/E ratio: 80/20 and non-recourse financing.
Average interest rate on the debt: 6.55% with 3 years grace period and 15 years.
Repayment period in RMB.
In other word 3.6 Mn RMB per MW.
Key financial estimates: The tariff forecast is based on local benchmark tariffs and In-
flation acts on 80% of the tariff excl. VAT. Adjustments on the tariff are due to potential
increase of benchmark unit investment from 2023. IRR is above standard level.
Case study 2: Infrastructure funds represent strong options as they can provide
debt and equity and even go to a high ownership level in North Sweden
The Markbygden Ett project in northern Sweden is Europe’s largest single-site on-
shore wind farm. Located close to the Arctic Circle, the project will utilize 179 of GE
Renewables’ 3.6MW turbines, which are optimally equipped for the site’s wind speeds and climate.
To make it financeable, the project needed a buyer to commit to a substantial portion
of the energy the wind farm would produce. Before Macquarie invested 50%, a PPA
was negotiated with Norsk Hydro, as well as a 19 years offtake.
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Table 19 : The Markbygden Ett project
The EU has ambitious climate and energy targets for 2030, aiming to provide affordable,
secure and sustainable energy. To date, government subsidies have been used to keep
the price of renewable energy competitive and encourage lenders to commit develop-
ment capital to projects.
Increasingly, European governments expect renewables projects to be commercially via-
ble in their own right, which is requiring a new approach to financing.
Markbydgen Ett shows how corporate PPAs can offer renewable energy projects a genu-
ine long-term funding alternative to government subsidies. Done properly, they can make
lenders more comfortable providing finance while simultaneously enhancing the value of
the project.
4.4.4 The Private Lenders
On the lending side we find on one hand the infrastructure funds with somehow higher
expectations than the private banks. As global leaders, all large banks as HSBC, BNP
Paribas, Société Générale, SMBC, ICBC, Bank of China, VTB, Deutsche Bank, have
dedicated teams within their Corporate and investment banking teams. Of course the in-
volvement of local financial institution is also a plus.
The banking sector remains the dominant player in the Mongolian financial system with
more than 95 per cent of total assets. Concentration is extremely high with the three
largest banks holding nearly 70 per cent of banking assets. Non-banking financial institu-
tions, such as insurance companies, micro-finance institutions and savings and credit
cooperatives, remain very small in terms of asset size. There is no corporate bond mar-
ket in Mongolia and it is not expected to develop in the near future, as the handful of high
credit corporate borrowers have been heavily serviced by the banks and there is present-
ly limited economic incentive for borrowers or investors to develop the corporate bond
market. The equity market is more of a trading venue for few shares and does not play a
significant role in providing financing to the broader economy. The Mongolian market also
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lacks long-term financing sources, as there are no substantial institutional investors, such
as life insurance providers and pension funds, to invest in long-term financial products.
There are only 5 international banks with a presence in Mongolia: Bank of China, ICBC,
ING, MUFG, and SMBC. It means beyond those financial institutions, private lenders
come in general from international banks operating through some of their international of-
fices when they deal about Mongolia project financing.
Case study: In debt financing, local banks are also relevant financing sources as in
Vietnam
Commercial banks have interest to provide loans for green energy projects as in Vi-
etnam, where local banks take their own piece of the pie.
HDBank – has so far also planned to set aside up to VNĐ7 trillion for the construction of green energy projects from now to 2020. Under HDBank’s plans, it will lend to projects which were approved by the Government and reach their commercial operation date before June
30, 2019.
To qualify for the bank’s loans, borrowers must have a minimum equity of VNĐ150 billion and the equity ratio in their projects must be at least 30 per cent of the projects’ total invest-ment capital. The bank also requires that all proceeds from the projects be transferred to the
customers’ accounts at HDBank.
According to the Vietnamese Government, only solar energy projects which reach commer-
cial operation dates before June 30, 2019 qualify to enjoy the FiT of 9.35 US cents per kWh.
The deadline for onshore and offshore wind power projects to get the FiT of VNĐ1, 928 (8.5 US cents) and VNĐ2, 223 (9.8 US cents) per kWh, respectively, is November 1, 2021.
4.4.5 Other sources of funding
Other sources of funding may include bond issuance or public listing which depends on the
project sponsors, the guarantees given to investors and the expected capitalization.
4.5 THE INVESTMENT IN MONGOLIA AS OF TODAY
4.5.1 Foreign direct investment is on continuous rise showing good perspective to Mongolia attractiveness
Foreign Direct Investment in Mongolia increased by 19379.30 USD Million in the third quarter
of 2018. Foreign Direct Investment in Mongolia averaged 17221.81 USD Million from 2010
until 2018, reaching an all-time high of 20903.50 USD Million in the first quarter of 2016 and
a record low of 8444.70 USD Million in the fourth quarter of 2010.
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Figure 53 : Foreign Direct Investment in Mongolia
Foreign Direct Investment in Mongolia is expected to be 19000.00 USD Million by the end of
this quarter, according to Trading Economics global macro models and analysts’ expecta-
tions. Looking forward, we estimate Foreign Direct Investment in Mongolia to stand at
19900.00 in 12-month time. In the long-term, the Mongolia Foreign Direct Investment is pro-
jected to trend around 20100.00 USD Million in 2020, according to our econometric models.
4.5.2 With a target of 30% of renewable energies, renewables offer op-portunities for the Mongolian economy
Case study 1: a successful project - the Tsetsii Wind farm
Figure 54 : Tsetsii Wind farm
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4.5.3 Conventional Power remains questionable
Case Study 2: The CHP5, long delays and international coal policies have stopped what
could have been a huge project
Figure 55 : CHP5
Case Study 3: the Oyu Tolgoi project, how to trigger international finance interest
through a bring JV between the GOM and a leading strategic partner
OT Investment and Project Financing
Some $6.4 billion has been invested to develop the open-pit mine at Oyu Tolgoi, with an ad-
ditional $500 million of capital costs for initial development of the underground mine.
The development of the Oyu Tolgoi underground mine in Mongolia took an important step
forward on 15 December 2015 with the signing of a US$4.4 billion project financing agree-
ment. Oyu Tolgoi has secured Project Finance for the underground mine development with
funding by international financial institutions and export credit agencies representing the
governments of the United States, Canada and Australia, along with 15 commercial banks.
Oyu Tolgoi Underground Mine Development and Financing Plan was agreed upon by the
Government of Mongolia, Turquoise Hill Resources and Rio Tinto, which set out a pathway
towards development, including the basis for the funding of the project.
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Under the project financing, Initial Senior Loans will total $4.4 billion and will consist of facili-
ties provided and funded by Export Development Canada (“EDC”), the European Bank for
Reconstruction and Development (“EBRD”), the International Finance Corporation (“IFC”), the Export-Import Bank of the United States, the Export Finance and Insurance Corporation
of Australia (“Efic”) and commercial lenders comprising BNP Paribas, ANZ, ING, Société
Générale Corporate & Investment Banking, Sumitomo Mitsui, Standard Chartered Bank, Ca-
nadian Imperial Bank of Commerce, Crédit Agricole, Intesa Sanpaolo, National Australia
Bank, Natixis, HSBC, The Bank of Tokyo-Mitsubishi UFJ, KfW IPEX-Bank and Nederlandse
Financierings-Maatschappij voor Ontwikkelingslanden. The Multilateral Investment Guaran-
tee Agency (MIGA) provided political risk insurance for the commercial banks.
EDC, EBRD, IFC and BNP Paribas acted as Initial Mandated Lead Arrangers and Standard
Chartered Bank as Initial Lead Arranger. BNP Paribas was the sole bookrunner of the $2.34
billion facilities funded by the commercial banks, together with EBRD and IFC on their re-
spective B loans.
The parties have agreed a debt cap of $6 billion, providing the option for an additional $1.6
billion of Supplemental Debt in future.
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4.6 APPETITE FOR EQUITY / DEBT INVESTMENT: BOTTOM UP METHOD WITH QUESTIONNAIRE
The idea there is to meet the investors that are present in Mongolia to get their preliminary
feedbacks. To start to qualify the appetite of potential investors to a NAPSI project, we inter-
viewed some of the key players in Mongolia.
There are 3 multilateral banks and 5 foreign banks in Mongolia not including the Mongolian
banks.
Table 20 : Potential investors that are present in Mongolia
Our methodology has been a traditional bottom up analysis framework
Figure 56 : Assessment methodology
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We have structure a questionnaire around 16 questions to drive the discussions with the
Mongolian pool of investors.
Questionnaire:
1. What do you know about the NAPSI (North Asia Power System Integration) project and
the plan to develop an energy capacity in Mongolia?
2. As a preliminary question, how would you rate investment entry environment and how
difficult is it to develop investment in the infrastructures sector, including energy, in Mon-
golia?
3. What are the main on ground de-facto barriers of investment in Mongolia? For example
trading cross borders, export-import procedures, licensing, government commitments,...
4. For you, is renewable energy having the potential to become the main sector of diversi-
fying Mongolian economy? If so, on what grounds?
5. If the Government of Mongolia, were to select investors on selected renewable energy
concessions, what would be for you the best process to be handled? For example: ten-
dering process after or without adjustment of the appropriate laws,…?
6. If your organization were to be contacted, how would you appreciate those kinds of pro-
jects in Mongolia?
7. What would be your organization appetite to invest in such kind of project in Mongolia?
8. What should be the key success factor from your point of view for such projects to hap-
pen?
9. How would be your organization appreciating investing in renewable projects or conven-tional projects to stabilize the output from renewable energy? Would you be considering as well investing in the grid development?
10. Viewed from your organization, what are the main advantages of investment projects in Mongolia?
11. What could be some of the reason why not to invest in Mongolia in such projects?
12. What are the risks you are considering which should be mitigated regarding this type of investment in Mongolia and how those could be improved by an adjusted framework?
13. Regarding investment in Mongolia vs. North Asian or Central Asian countries, what are the differences between investing in Mongolia and those other countries and what should be done to improve the attractiveness of Mongolia, if any?
14. What is your opinion regarding the designated Government agency that oversees the matter of investment such as the National Development Agency and is there any ra-tionale for improvement if any?
15. In your opinion, knowing the opinion counts in a country like Mongolia, how often do the public perception swing and how much constant management and sustained effort need-ed for managing public perception? Is this a potential barrier?
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To illustrate the type of investment to be financed, we have sent three case representing the
type of assets to be financed:
• A renewable energy case in Mongolia: Salkhit
• A conventional energy case : USCF Powerplant
• A 1.5 bn € grid investment between two countries
• Those case have been integrated in the appendices
• The main aim was to share some knowledge about the topic to be discussed and il-
lustrate through case studies the questionnaire sent to the financial institutions
Synthesis of the interviews:
NAPSI awareness remains limited among the players we have interviewed Among the stakeholders we have interviewed, some became aware of the NAPSI project
in receiving our invitation email for interview, some had heard about the project and only
had a high level perception. They understand the project is at an early stage, whenever
there are some available public information enabling to learn more about NAPSI;
Nevertheless they is a general awareness about Renewable Energies in Mongolia and as
mentioned by one of our interviewee, the concept of NAPSI makes sense
In terms of potential there is no doubt about it, nevertheless:
The project complexity is understood with the coordination of 5 countries;
The size of the project costs makes it crucial to validate its bankability;
While the Mongolian energy sector is moving into renewable energies, there is a huge
One of the key challenge for the next steps of the NAPSI project will be the promotion of the
project to create awareness and credibility among the investment community regarding the
development of such project in Mongolia
The perception of the investment environment in Mongolia can create a potential bar-
rier
• A main concerns highlighted was the political stability and its impact in the Mongolian
economic ecosystem and the concern regarding the long term stability of the decision,
the risk of changing already taken measures and delays to implement which may put at
risk the benefit of the investment for the country;
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• There are lot of rooms for improvement and giving the investors more security in terms
of tariffs, offtake,… and ways to provide continuity in the agreements that have been
signed;
• The economic situation of the country can be seen as another issue bringing the
Mongolian expected returns higher than any other countries of the region but well framed
the NAPSI project would be potentially an option to lower the depencies to commodities
and as an export driven industry, there could be some factors to decorelate the risk from
the country risk
• The perceived lack of transparency on some decision led some of our interviewees
question their participation in a tender
• Finally a last point was raised on connectivities
Figure 57 : Mongolia risk assessment methodology
Most off the risks are political and economic driven ones, but there are ways to miti-
gate them…
Perceived risk factors
> Stability of the Government and policies requiring the improvement of the legislative sys-tem;
> Economic volatility ultra-dependent from a few commodities leading to a high cost of funds, as well as a limited financial sector;
> Weakly and incomprehensively formulated laws and regulations and its improper imple-mentation;
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> A framework to be implemented independently: tariffs and offtake;
> Perception of risk if the tender if handled at GoM level;
> Logistic costs are high in Mongolia and should be reduced to increase competitiveness;
> Maturity of the NAPSI project: it must have acquired all the permits, licenses and PPEs before tendering;
> Getting the support of the opinion
Risk mitigation factors
> Attractiveness of Mongolia is obvious due to its wide area with a quasi-absence of popu-lation in some areas, low population and an over abundant resource of wind and sun, as well as coal to stabilize the wind farms output;
> Location of Mongolia as landlocked in a region of super-powers: China, Japan, Korea and Russia;
> The presence of Multilateral Financial Organization in projects such as the ones that will be derived from the NAPSI project is a real opportunity to bring FDI as those are per-ceived to know Mongolia for long and increase the credibility on the projects they invest in;
> More political stability is involved to make the projects successful, or other words, it is necessary to bring the NAPSI projects independent from the Mongolian political land-scape including the tendering process which is recommended to be handled by an inde-pendent third party.;
> The prospect of the energy diversification to stabilize the economy and the relationship with the LSE;
> Early stage of the NAPSI project enabling in further stages create an adequate legal and a clear financial framework involving or not the GoM, with tariffs and offtakes agree-ments..
Investing in renewable energies offers a significant interest from the investors we met
• Some investors keep somehow skeptical regarding the development of a disruptive mas-sive renewable capacity dedicated to export due to the current economy structure with the strong presence of coal as main contributor to power generation, and the political di-mension of the project requiring to ensure offtakes and transmission from the other NAPSI countries;
• Nevertheless renewables power generation is viewed as a real opportunity for Mongolia in terms of diversification and a possibility to become one pillar of the economy, thanks to the abundant wind and solar resources, without considering to rebalance the economy;
• A key driver for investors to move forward and to make the projects bankable would be the visibility in the regulatory framework especially on tariffs, the long term sustainability
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regarding the main components of the business cases to ensure that the environment will be predictable during the whole duration of the project;
• A challenge appeared in the development of the grid which should involve a government commitment to be further defined;
• One key success factor for the financial institutions would be to involve the Multilateral Financial Institution as a kind of guarantee for private investors. If local bank should be involved to some extend, offshore project financing will be mandatory with the local banks bringing their market knowledge and supporting the local companies involved in such projects
Coal may support the development of a stable output of energy but some investors
may be reluctant
Figure 58 : Pro and cons analysis for coal in Mongolia
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www.edf.fr
4.7 LESSONS LEARNED FOR NAPSI
Large scales renewable projects are one of the core project financing globally
In emerging economies, Multilateral Financial Institutions (MFIs) have proven to be
playing decisive roles to convince other investors to move on in giving them confi-dence
As equity investors, expectations are not the same between
MFIs which have a willingness to support the economy vs. high yield
Strategic investors which will look at an IRR but have also other ways to be com-pensated as management service agreements, synergies with existing/future businesses
Infrastructure funds which target higher yield and may have an exit strategy in their pitches
Lenders may be MFIs or international lenders, but the role of the local banks should not be underestimated in a pool of lenders to which they can be the local interface
But in any case, attracting investors means guarantees:
By Government
Stability of the ecosystem which in NAPSI should go through a NAPSI Authority
Agreement on foreign offtake and PPA to ensure the business plan stability
Access to international financial market will also require the scalability with a question to be answered: shall the NAPSI project concessions be sizable (1GW each or more) and 1 grid concession, and will there be some ownership from the State of Mongolia which could be some models to be presented in June
From the interviews, we have learnt that attracting investors on the NAPSI project will
require to give some assurance due to the scale of the investment:
One of the main success factor should be to provide the investors some guarantees
regarding the stability of their investment in the long run, and the independence to the Mongolian political environment;
The development of an independent NAPSI authority, located in Ulaanbaatar could be an option in order to provide the required independence from the Government of Mongolia and to contribute to the coordination of the potential issues between the countries;
The concession process should be handle by a third part consultant show as much transparency as possible to the investors;
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www.edf.fr
There should be prior agreement on the tariffs and offtakes in order to provide the stability required in the long term for a business case;
Hybrid model are financeable as some investors are still considering coal in such case to stabilize the output;
The grid may require some involvement of the Mongolian Government or related par-ties;
Mongolian banks should have a role to play, while not competitive in terms of interest rates, they will act as local expert;
With appropriate off takers, there could be ways de-correlating the expected returns to the expected ones in a project in Mongolia.
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www.edf.fr
5 GENERAL CONCLUSIONS
The recommendations for the organization of NEA Power Trade are the followings:
At first step: implement a strong NEA Regulatory Coordination
As target of a NAPSI Authority for monitoring the regional and national regulation
modifications and managing the interconnection infrastructure projects
Figure 59 : The NAPSI Authority organization
Harmonize the national Regulations at regional level
Regional Regulation :
Mission to National Regulatory Authorities (NRAs)
o Free regional market for all players
o Power trade contracts standardization
o Institutionalization of competitive mechanisms
o Regional Grid Code: Clear common rules
o Transmission rights: Development of comprehensive methodology
o Same priority for domestic demand and export commitments with sanction
agreement in case of non-respect.
National Regulations
o Third Party Access (TPA): Transparent and non-discriminatory access to in-
terconnection has to be guaranteed for all players especially IPP
o Independence of NRA (encouraged by law)
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Develop new interconnectors through a non-discriminatory market based ap-
proach
The preferred method is basically to finance the interconnectors by the 2 TSOs by the
regulated regime
Letting the option open for partial (hybrid) or full financing by the private sector
The Regulatory Coordination should provide additional grants to complete the financ-
ing in compensation of the economic benefit for other TSOs
Organize a market model where the cost recovery of interconnectors does not af-
fect the cost of exchanges of electricity:
recover the cost through Transmission Right Auctions reserving:
o Explicit auctions for long term: from yearly to weekly
o Implicit auctions for short term: Day Ahead
In real time, the remaining capacities should be handled by the TSO’s through their own balancing markets.
This methodology guarantees that exported low price energy will remain cost-
effective in the importing country independently from the cost of the interconnection.
Figure 60 : Recommended cost recovery methodology for interconnectors
The basic reason of the efficiency of this methodology that is used in Europe is the separa-
tion between 2 businesses:
• The Interconnection service with dedicated costs & revenues
• The Generation and Exchange of electricity between countries
Figure 61 : Illustration of the recommended interconnector cost recovery methodology
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This methodology ensures that no Transmission costs will be added to generation cost and
this is very important so that the cost-effectiveness of the Solar and Wind electricity produced
in Mongolia remain the same in the other countries.
This principle guaranties free access in all the national markets to the most cost effective
electricity provided:
o The Independence of TSOs (encouraged by policies)
o The creation of a Balancing market
o The Market operator: TSO or separate entity
The recommendations for Mongolia are the followings:
Organize the 500kV HVAC Grid Update according to 2 possible options:
N°1: through BOOT by NEA TSOs
N°2: through BOOT by China and Russia
With Cost recovery through Transmission Right Auctions
Figure 62 : Recommended Mongolia’s grid upgrade
Regarding new Conventional Generation:
There is a new deal for coal after Paris agreement: only some lenders still may pro-
vide financing for coal-fired Power Plants
Hybrid (electricity and heat) may still be possible by Western financing as long as it
contributes only to stabilized the output of renewable generation
with the same recommendations as Renewable Power (see below)
Develop a specific Regulation for favoring attractiveness of private foreign and
local investors in Renewable Energies
For giving enough visibility on the renewable energy policy targets
For ensuring foreseeable and stable Revenues
For guarantying the Grid Operation: Priority dispatch / no curtailment
For guarantying the Grid connection with enough capacity on short and long run
For improving the Contractual and Legal maturity
For developing adequate Financing facilities
For getting liable pre-permitted sites,
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www.edf.fr
MINISTRY OF ENERGY, GOVERNMENT OF MONGOLIA
Government Building 14, Khan-Uul District
Chinggis Avenue, 3-r Khoroo
Ulaanbaatar, 17060 Mongolia
Contact: Mr. Bavuudorj Ovgor
Director of Renewable Energy Division
ASIAN DEVELOPMENT BANK
6 ADB Avenue
Mandaluyong City, 1550
Metro Manila, Philippines
Contact: Mr. Kaoru Ogino
Project Manager, Energy Division (EAEN), East Asia Department (EARD)
Consultant: EDF
EDF CIST, Immeuble Spallis, 2 rue Michel Faraday
93282 Saint-Denis Cedex
France
Contact: Mr. Philippe Lienhart
Strategy Innovation New Business Manager
Strategy for NAPSI Technical Assistance to Mongolia Team Leader
Deliverable: Module 6 Report on Power Trade and Regulation
Date: 28th February 2019