48030-001: Strategy for Northeast Asia Power System ... · Technical Assistance Consultant’s Report Project Number: 48030-001 February 2020 Mongolia: Strategy for Northeast Asia

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.

Module 6 report on Power Trade and Regulation - May 2019

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EDF ELECTRICITE DE FRANCE – with a capital of 1 006 625 696.50 euros – TA-9001 MON: Strategy for Northeast Asia Power System Interconnection

552 081 371 R.C.S. Paris EDF References: CIST – DCO – PhL – 19 - 145

www.edf.fr

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 14 : Schematic diagram of African overall power grid pattern in 2030 ....................... 31



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


Phase 3: after 2022

Regulated Transmission Tariff : Local Marginal Price / Nodal Price



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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.



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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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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.

https://en.wikipedia.org/wiki/Directive_(European_Union)

https://en.wikipedia.org/wiki/Regulation_(European_Union)

https://en.wikipedia.org/wiki/Internal_Market_in_Electricity_Directive

https://en.wikipedia.org/wiki/Energy_infrastructure


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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

http://www.acer.europa.eu/en/Pages/default.aspx

https://ec.europa.eu/energy/en/topics/markets-and-consumers/single-market-progress-report

https://ec.europa.eu/commission/priorities/energy-union-and-climate_en


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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:



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:



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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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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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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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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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)

[email protected]

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

[email protected]

Deliverable: Module 6 Report on Power Trade and Regulation

Date: 28th February 2019

Documents

48030-001: Strategy for Northeast Asia Power System ... · Technical Assistance Consultant’s Report Project Number: 48030-001 February 2020 Mongolia: Strategy for Northeast Asia