Gap_Analysis_with_List_of_Market_Challenges_and_Legal_Barriers,_EC-LEDS,_June_2016.pdf

June 2016

This publication was produced for review by the United States Agency for International Development (USAID).

It was prepared by IRG, an Engility Company.

ARMENIA GAP ANALYSIS

WITH LIST OF MARKET CHALLENGES AND

LEGAL BARRIERS

ENHANCING CAPACITY FOR LOW EMISSION DEVELOPMENT STRATEGIES

(EC-LEDS) PROJECT

CONTRACT NUMBER AID-OAA-M-15-00005

ARMENIA GAP ANALYSIS

WITH LIST OF MARKET CHALLENGES AND

LEGAL BARRIERS

Enhancing Capacity for Low Emission Development Strategies (EC-LEDS) Project

Contract Number AID-OAA-M-15-00005

June 2016

DISCLAIMER

The author’s views expressed in this publication do not necessarily reflect the views of the United States Agency for International Development or the United States Government.

This page is intentionally left blank.

ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS I

TABLE OF CONTENTS

1. INTRODUCTION ················································································ 1

2. EXECUTIVE SUMMARY ······································································· 3

3. POWER SYSTEM OF ARMENIA ···························································· 7

3.1 Technical Indicators of the Power System

3.2 Institutional Framework

3.3 Wholesale Power Market Regulations

3.4 Export and Import Regulations

3.5 Structure of the Tariffs

3.6 Future Development Plans

3.7 Transmission Development Impact on Cross-Border Trade

4. SITUATION IN THE POWER MARKET OF GEORGIA ··························· 19

4.1 Domestic Market Principles and Cross-Border Trade

4.2 Generation and Transmission Development Impact on Cross-Border Trade

4.3 Trade Between Georgia and Turkey

4.4 Trade Between Georgia and Russia

5. TRADE POSSIBILITIES BETWEEN ARMENIA AND GEORGIA ·············· 27

5.1 Export from Armenia

5.2 Seasonal Import from Georgia and Daily Exchange

6. EU REQUIREMENTS FOR INTERNAL POWER MARKET ······················· 29

6.1 Electricity

6.2 Regulatory Authority

6.3 Renewable Energy

6.4 Energy Efficiency

6.5 Environment

6.6 Competition

6.7 Statistics

7. GAP ANALYSIS ·················································································· 37

8. MARKET CHALLENGES AND LEGAL BARRIERS ·································· 39

8.1 Legal Barriers

8.2 Market Challenges

8.2.1 Domestic Market

8.2.2 Cross-Border Trade

9. SUMMARY AND RECOMMENDATIONS ·············································· 47

II ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

LIST OF FIGURES

Figure 1. Armenian Interconnections Figure 2. Coruh River HPP Cascade Development Plan Figure 3. Turkish Transmission System

LIST OF TABLES

Table 1. Main Annual Data of Electricity Balance in GWh Table 2. New Generation in Georgia Table 3. Georgian Import from Russia in GWh Table 4. Gap Analysis Comparing Armenian Legal/Regulatory Framework to EU Internal

Power Market Requirements Table 5. List of Strategic Market Challenges and Legal Barriers

ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS III

ACRONYMS

AMD Armenian Dram(s)

B2B Back-to-Back

CCGT Combined Cycle Gas Turbine

CJSC Closed Joint Stock Company

DCFTA Deep and Comprehensive Free Trade Area

DISCO Distribution Company

DSO Distribution System Operator

EC-LEDS Enhancing Capacity for Low Emission Development Strategies

EE Energy Efficiency

ENTSO-E European Network of Transmission System Operators for Electricity

EPSO Electro Power System Operator

EU European Union

EUROSTAT Statistical Office of the European Union

GEL Georgian Lari

GNERC Georgian National Energy and Water Supply Regulatory Commission

GO Guarantee of Origin

GoA Government of Armenia

GWh Gigawatt Hour(s)

HIPP Hydropower Investment Promotion Project

HPP Hydropower Plant

HVEN High-Voltage Electric Networks

IBRD International Bank for Reconstruction and Development

IRG IRG, an Engility Company

ISO Independent System Operator

Kcal Kilocalorie

KfW KfW Development Bank kg Kilogram(s)

IV ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

kV Kilovolt(s) kWh Kilowatt Hour(s)

LCEDP Least-Cost Energy Development Plan m3 Cubic Meter(s)

MO Market Operator

MoENR Ministry of Energy and Natural Resources of Armenia

MOU Memorandum of Understanding

MVA Mega Volt Ampere(s)

MW Megawatt(s)

MWh Megawatt Hour(s)

NPP Nuclear Power Plant

PPA Power Purchase Agreement

PSRC Public Services Regulatory Commission of Armenia

PV Photovoltaic

RE Renewable Energy

RoA Republic of Armenia

S.M.A.R.T. Specific, Measurable, Assignable, Realistic, and Timely

SEE Southeast Europe

SREP Scaling-up Renewable Energy Program tcm Thousand Cubic Meters

TO Transmission Operator

TPP Thermal Power Plant

TSO Transmission System Operator

USAID United States Agency for International Development

USD United States Dollar

VAT Value Added Tax

1. INTRODUCTION

This Draft Armenia Gap Analysis with List of Market Challenges and Legal Barriers report has been prepared under the USAID Enhancing Capacity for Low Emission Development Strategies (EC- LEDS) led by IRG, an Engility Company and a team of local and international experts. The EC- LEDS project in Armenia intends to support a national energy strategy, corresponding market reforms, and promote cross-border trade with Georgia. This includes working toward the harmonization of Armenian regulatory practices and power system standards with those of Georgia to comply with European Union (EU) directives.

The purpose of this report is to provide a gap analysis and develop a list of major market challenges and legal barriers facing the Armenian power sector. The report describes an analysis of the power system of Armenia, including generation capacities, the current market design, export and import regulations, tariffs, and future development plans. An analysis of transmission development on cross-border trade for Armenia is discussed in a separate chapter along with interconnection status and other development considerations. The report also provides an analysis of the power market of Georgia focusing on existing trade relations with neighboring countries, especially Armenia.

EU energy directives cover a wide range of electricity market features, including market design rules, regulatory authority, renewable energy (RE) issues, energy efficiency (EE) requirements, environmental issues, data development and statistical reporting, and rules for competition. The gap analysis compares the Armenian legal and regulatory framework and market design to EU internal electricity market features. Market challenges and legal barriers are discussed in detail for domestic market and cross-border trade with Georgia. The conclusions and recommendations consider strategic challenges, possible negative effect of changes on the status quo, the legal basis of power market, and barriers to change. The report concludes with several recommendations.

2 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

2. EXECUTIVE SUMMARY

This report was commissioned to examine the compliance of Armenian regulations in the power sector with the EU directives and to define market challenges and legal barriers for advancing the internal power market and trade with Georgia. The current market design for Armenia was implemented more than 10 years ago and falls short of legal, regulatory, and Market Rules necessary to improve trade with Georgia.

To improve the functioning of internal energy markets and resolve structural problems, the EU sets energy market requirements for transparent market and network operations, competitive wholesale and retail markets designed for consumer benefit, increased cross-border cooperation between Transmission System Operators (TSOs), and unbundling energy suppliers from network operators.

The current Energy Law in Armenia does not comply with EU requirements, and many requirements for market and network operations are not clearly covered in the law. To achieve greater competitiveness, a new Energy Law based on the principles of the EU directives is needed.

Armenia’s power market is not yet competitive and has a long list of market challenges. Although some unbundling has occurred, the power market remains a monopoly under a single-buyer market structure. There is only one power distribution company (DISCO), and customers do not have a choice of a power supply company. Distribution was not unbundled into a Distribution System Operator (DSO) and suppliers and there are no clear rules guaranteeing third party access to transmission and distribution networks. There are no Market Rules for settling deviations between contracted and delivered amounts of power. Balancing is accomplished by an Independent System Operator (ISO) in cooperation with the DSO on an annual basis. There are no strict regulatory mechanisms to protect vulnerable customers; however, the Government of Armenia (GoA) uses different mechanisms to protect such customers through targeted and “means tested” social support schemes. Moreover, the GoA, Ministry of Energy and Natural Resources of Armenia (MoENR), and Regulator authorize new generating capacities that may include concessions. There is no Market Operator (MO) because the existing regulations are not systemized into the Market Rules and the Network Rules (Grid Code) are not yet developed.

Current regulations for the internal market as well as tariff rules for export/import transactions have unnecessary restrictions on sector development, which makes the market less attractive for private investments. Import/export transactions are licensed, and the Regulator sets tariffs for imported electricity, but not for exported electricity. The Regulator issues licenses within 80 working days and the importer/exporter must pay about $10,000 United States Dollars (USD) annually and provide a bank guarantee for about $1,000. Market Rules are defined only for export and require the exporter to sign contracts with a generation unit, the Electro Power System Operator (EPSO), TSO, and the Settlement Center. More importantly, the rule permits only Hrazdan Unit5 or the Hrazdan thermal power plant (TPP) to export power. In addition, the Regulator registers import/export contracts, which takes another 10 working days. These regulations obviously make the export/import possibilities complicated and therefore require fundamental revision.

Tariffs are regulated using rate of return methodology, which does not provide sufficient incentives for optimizing costs of regulated monopolies. Distribution tariffs are not yet determined. The absence of a proper legal framework artificially restricts consumers’ rights to import electricity from neighboring countries. End-user tariffs are differentiated by voltage levels for day and nighttime tariffs, and there are no capacity charges, peak tariffs, or service fees. As a result, customers have no responsibility for defined capacity charges for large generation. The average difference between day and night tariffs is insignificant: for high voltage customers (i.e., 35 to 110 kilovolts (kV)), it is only

4 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

12 percent and, for middle (6 to 10 kV) and low voltage (0.22 to 0.4 kV) customers, it is only 26 percent. These differences do not support load management efforts.

Future development plans for the rehabilitation of the Armenia nuclear power plant (NPP), construction of a new combined cycle gas turbine (CCGT) units and hydropower plants (HPPs), and transmission system upgrades will bring new challenges and opportunities to the Armenia power market. The gradual liberalization of the power market and development of new instruments for trade with Georgia can help to meet these challenges.

Georgia has signed the Deep and Comprehensive Free Trade Area (DCFTA) and Association Agreements with the EU and is changing its internal regulations in compliance with EU criteria - the country has developed a market opening implementation plan and created a relevant market structure.

Armenia and Georgia are developing the necessary interconnection infrastructure to support trade between countries; however they can increase the efficiency of their internal power markets through development of relevant trade and system integration mechanisms, which will reduce a number of challenges typically faced by countries with a transitional economy.

To maximize the trade benefits, Armenia needs to implement the following reforms:

• Domestic consumer protection through: 1) pricing system modifications and 2) allocating responsibilities between market participants and end-users

• Fair allocation of responsibilities between market participants

• Improved incentives for private investors

• Increased opportunities for beneficial cross-border trade

It is probably important to first consider: 1) a new system of tariff approval, 2) transition to an hourly market, 3) long- and short-term balancing operations, 4) developing transparent and nondiscriminatory electricity markets, and 5) better correspondence between real consumptions growth/cross-border trade opportunities and investments. A gradual transition to a new market is needed, and this will be reflected in the next Armenia New Electricity Market Initial Design and Action Plan to Support the Regional Trade report.

Given that competition in wholesale and retail supply is a dominant feature of the Energy Community Treaty and the regional power integration process, it is not surprising that Armenia’s power sector falls well short of meeting those requirements. This is apparent in the gap analysis that compares Armenia’s power sector legal/legislative framework and market design versus the Secretariat’s evaluation criteria.

Armenia’s power sector indeed faces numerous challenges--beginning with increasing demand and an inefficient market and poor tariff structure. Opportunities for trade with Georgia could provide new benefits and help address many challenges in Armenia’s power sector. A coordinated approach to modifying the domestic power market and improvements in the legal/regulatory framework with Georgia could provide additional benefits to Armenia. In this regard, it is recommended to “restart the power market,” by giving life to a new model, developing a transitional market design with a scenario for gradual market opening to competition, and moving from “regulation” to “deregulation” with incentive-based regulation instruments.

As basic steps, the following actions are recommended for early implementation:

• Set up distribution tariffs - a prerequisite step for opening the market even for a very small portion of customers.

• Create an MO that will be responsible for organizing proper trade mechanisms in the internal market and on a regional basis. To ensure full independence of the MO and enhance its impartiality and transparency of decision-making, the GoA could transfer its shares directly to market participants.

• Separate distribution from supply, and create differentiated regulations for those entities.

• Simplify export and import rules.

• Create Network Rules and basic Market Rules, and set up transitional phases for market reforms.

6 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

3. POWER SYSTEM OF

ARMENIA

3.1 TECHNICAL INDICATORS OF THE POWER SYSTEM

Generation produces enough electricity to meet domestic demand, which is about 6,5001 gigawatt hours (GWh) annually with an average growth of 2 percent. The total operating capacity of all generation units is about 2,400 MW and, after the decommissioning of the Hrazdan TPP in 2019, it will be 2,000 MW. Domestic demand is covered by 37-percent nuclear, 31.5-percent thermal, and 31.5-percent hydro generation. Peak electricity demand is about 1,300 MW and is observed during November through February. Summer peak demand is around 900 MW. There are no seasonal deficits. Generation surplus consists of TPPs; the possible exporting capacity is Hrazdan Unit5.

The power system of Armenia includes the following power plants:2,3

• Nuclear Power Plants

– Armenian NPP: Government owned (“HAEK” Closed Joint Stock Company (CJSC));

operating capacity is 385 megawatts (MW) (installed capacity is 440 MW and the year of commissioning was 1980); annual generation is approximately 2,400 GWh, covering about 37 percent of domestic supply. The Armenian NPP is scheduled to be rehabilitated sometime during 2017 and 2018 for a service lifetime extension up to 10 years. The rehabilitation is expected to cost about a $300 million.

• Thermal Power Plants

– Hrazdan TPP: Private (“RazTES” CJSC); operating capacity is 400 MW (installed capacity is 1,110 MW and the year of commissioning was 1966 to 1974); the annual generation for the internal market is approximately 500 GWh, covering about 8 percent of domestic supply.

Planning for decommission is expected in 2019 due to its low efficiency.

– Hrazdan Unit5: Private (“Gazprom Armenia” CJSC); operating capacity is 440 MW (installed capacity is 467 MW and the year of commissioning was 2011); and annual generation for the internal market is approximately 500 GWh, covering about 8 percent of domestic supply. Projected annual generation of the unit is about 3,000 GWh; therefore, the internal market takes only 17 percent of it. Currently, Hrazdan Unit5 is more oriented toward exporting capacity.

– Yerevan CCGT: Government owned (“Yerevan TPC” CJSC); operating capacity is 220 MW (installed capacity is 238 MW and the year of commissioning was 2010); and annual generation for the internal market is approximately 950 GWh, covering about 15 percent of domestic supply. The Yerevan CCGT is working under a “gas-electricity” exchange contract, exporting about 500 GWh annually.

• Large Hydropower Plants

1. Data presented in the report are last year’s average.

2. www.minenergy.am/.

3. www.psrc.am/am/sectors/electric.

http://www.minenergy.am/ http://www.psrc.am/am/sectors/electric

8 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

– Vorotan Cascade: Private (“ContourGlobal Hydro Cascade” CJSC); operating capacity is 404 MW (installed capacity is 404 MW and the year of commissioning was 1970 to 1989);

and annual generation is approximately 1,000 GWh, covering about 15 percent of domestic supply. Vorotan Cascade’s assets are old and require extensive upgrading. The short-term rehabilitation plan with an investment cost of 51 million euros (€) is now under development.

– Sevan-Hrazdan Cascade: Private (“International Energy Corporation” CJSC); operating capacity is 552 MW (installed capacity is 561 MW and the year of commissioning was 1940 to 1962); and annual generation is approximately 450 GWh, covering about 6 percent of domestic supply. Different upgrades were done on the Cascade’s power plants during the last 15 years. At present, the Yerevan HPP is under reconstruction with investment costs of $40 million.

• Renewable Energy

– About 170 private, small HPPs (under 30 MW) are operating in the system and were generally constructed during the last 10 years. Installed capacity is about 300 MW, and annual generation is approximately 700 GWh, covering about 11 percent of domestic supply.

There are several small-size wind, bio, and solar plants that have limited impact on system supply.

The transmission system of Armenia is well developed and consists of 14 substations of 220 kV and 2 substations of 110 kV (overall, 33 transformers and a capacity of about 2,500 mega volt-amperes (MVA)), which were generally rehabilitated during the last 10 years or will be rehabilitated during the next 4 years. The grid is interconnected with Georgia (110 kV and 220 kV, dedicated island operation); Iran (220 kV, synchronous operation); and Turkey (220 kV, not in operation). The interconnection capacity with Georgia is about 200 MW and, with Iran, is 300 MW. Transmission system losses are around 1.8 percent. The Transmission Operator (TO) is a government-owned company (“High-Voltage Electric Networks (HVEN)” CJSC) that holds all the transmission assets within the country, but does not operate the system.

The distribution system includes 0.4 to 110 kV lines and transformers. Access to the grid is close to 100 percent. The DSO serves about one million customers and also provides last-mile service.

Household annual consumption is about 35 percent; large customers (i.e., industry, transport, water supply, and irrigation) account for about 30 percent; and the remaining 35 percent are public entities and small- to medium-size businesses. Distribution system losses are about 11 percent, metering is 100 percent, and the collection ratio is close to 100 percent. All customers of 35 to 110 kV and a large proportion of 6 to 10 kV customers are integrated into a data acquisition system; 30 percent of all customers are equipped with electronic meters. In 2014, the System Average Interruption Duration Index amounted to 8.81 hours, the System Average Interruption Frequency Index had 5.48 interruptions per customer, and the Customer Average Interruption Duration Index had 1.61 hours.

The DSO is a private company (“Electric Networks of Armenia” CJSC) and holds and operates all the distribution assets within the country.

The power system is dispatched by an ISO, which is a separate, government-owned company (EPSO CJSC). A supervisory control and data acquisition system has been installed on generation units and 220 kV substations.

The Settlement Center provides metering and billing services to wholesale power market participants.

The data acquisition system installed in 2001 with USAID financing provides wholesale electronic meter data collection with 30-minute intervals at the Settlement Center for billing purposes.

3.2 INSTITUTIONAL FRAMEWORK

Armenia’s power sector is regulated by the Energy Law adopted in 2001. The Energy Law provides some basic principles for national policy, but does not specify the authorities of the GoA or the

MoENR to declare the policy or the role of the MoENR in the power sector. At the same time, the Energy Law describes in detail authorities given to the Public Services Regulatory Commission of Armenia (PSRC, or Regulator), which are generally in compliance with the international best practices. The Regulator:4

• Issues licenses for wholesale power market participants, including import and export transactions.

• Sets the tariffs for generation, transmission, and distribution, including end-user tariffs and service fees for the system operator and Settlement Center. The Regulator sets the tariffs for imported electricity as well.

• Sets the Market Rules in cooperation with the MoENR.

• Sets the distribution rules, including connection rules.

The Energy Law does not comply with EU requirements. In order to improve the functioning of the internal energy market and resolve structural problems, the EU sets the basic energy market requirements that, among others, covers the following:

• Transparent Market and Network Rules

• Competitive power and retail markets for consumers’ benefits

• Cross-border cooperation between TSOs

• Unbundling energy suppliers from network operators5

These requirements are not clearly covered in Armenia’s Energy Law; therefore, it should be substantially revised. A new Energy Law based on the principles of the EU directives can lead the sector to a competitive power market.

3.3 WHOLESALE POWER MARKET REGULATIONS

The wholesale power market of Armenia has no elements of competition; it is fully regulated. Only legal entities can participate in the power sector; unbundling between generation, transmission, distribution, and other activities is required by the law.4 There are no comprehensive or consistent documents on Market Rules; only generation regulations presented in several decisions adopted by the Regulators. Despite considerable effort to develop a Grid Code, it has not yet been adopted.

The wholesale power market has the following regulations and characteristics:

• Generation is fully regulated with no competition. The Regulator permits one license for construction and operation. Generators have no permit to sell electricity to customers. A generation unit may export electricity only when the internal market is saturated and the sale does not contradict the interests of internal customers. Moreover, according to the Energy Law, only the most expensive generation can be exported, which practically means that Hrazdan TPP and Hrazdan Unit5 are the only generation units available for export. The amount of produced electricity is set as a “preliminary value” in the contracts6 between the DSO and generation units. Therefore generation units do not have any responsibility for the “contracted” electricity.

• Transmission is fully regulated. The Regulator permits one license to a TO for construction and management of the assets. There are no defined rules for third party nondiscriminatory access to the transmission system.

4. www.arlis.am/DocumentView.aspx?DocID=91484.

5. https://ec.europa.eu/energy/en/topics/markets-and-consumers/market-legislation.

6. www.arlis.am/DocumentView.aspx?DocID=88646.

http://www.arlis.am/DocumentView.aspx?DocID=91484 https://ec.europa.eu/energy/en/topics/markets-and-consumers/market-legislation http://www.arlis.am/DocumentView.aspx?DocID=88646

10 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

• Distribution is fully regulated. The Regulator permits one license for construction and operation. Until February 2016, distribution held exclusive rights for the supply of electricity to customers.7 There are no clear regulations for unbundling distribution from supply. De facto, the DSO is the only supplier and acts as a monopoly. The DSO purchases electricity from the national generating companies at regulated prices and on the basis of direct contracts. As a consequence, the wholesale market is a monopsony, with the DSO acting as a single buyer. The Regulator has not set the distribution tariffs. This fact restricts customers from importing electricity from neighboring countries because a legal basis is lacking. All the financial flows of the power sector go through the DSO. This creates higher risks for the market participants and customers when the forecasted generation mix is not “achieved” for any reason. In a situation when the DSO is not stable financially, especially if near bankruptcy, it could lead to the collapse of the power system. Such a situation arose during a recent crisis in the power sector of Armenia. Neither electricity nor capacity is a contractual value for the customers. Even large customers do not have any responsibility for the “contracted” electricity or capacity. Thus, the system annual balance creates direct risks for the DSO, but not for a generation unit or a single customer. Those risks are covered by the end-user tariffs based on the ex-post assessments.

• The ISO acts based on the Regulators’ permit (license). The Regulator sets monthly fees for the services of the ISO. The ISO is responsible for the operation and economic dispatch of the wholesale power market. The EU, for operation of the power sector, applies three general models: ISO, TSO, and Ownership Unbundling. Armenia is closest to the ISO model. However, the TSO model, which includes ISO and TO in one entity, is more responsible, transparent, and powerful in terms of financial stability since it owns and operates all transmission assets. Therefore, the GoA can switch to the TSO model if it is not planning to privatize HVEN.

• The Settlement Center acts based on the Regulators’ permit (license) as well with regulated monthly fees. The Settlement Center is responsible for metering and billing issues on the wholesale market. The Settlement Center has no other essential activities. In EU power markets, this role is usually expanded to act as a MO with responsibility for organizing power markets.

3.4 EXPORT AND IMPORT REGULATIONS

Export and import principles are set in the Energy Law, and regulations are set by secondary legislation. The following regulations concern the export and import of electricity:

• The Energy Law states that any legal entity for export/import transactions must get a license, and all contracts before becoming effective must be registered by the Regulator. At the same time, the Regulator sets the licensing and contracts registration procedures. The Energy Law also defines the responsibilities of EPSO, which is the entity responsible for coordinating import/export power flows and system dispatch. An export license is issued only when the internal market demand is fully covered and the export of electricity will not impair the interests of domestic consumers.8 At the same time, the Regulator sets tariffs for imported electricity. Prices for exported electricity are not regulated.

• Licensing rules9 require that the exporter/importer provide: 1) the EPSO’s written approval that the import/export flows under the planned regime are reasonably possible; 2) the approved national budget fee payment (about $10,000 annually) and a bank guarantee (about

7. www.psrc.am/images/News/haytararutyun/2016/10.02.16/1.pdf.

8. RoA Energy Law.

9. www.arlis.am/DocumentView.aspx?DocID=86891.

http://www.psrc.am/images/News/haytararutyun/2016/10.02.16/1.pdf http://www.arlis.am/DocumentView.aspx?DocID=86891

$1,000); and 3) the applicant’s contract with a foreign vendor (does not apply in cases of export contracts). The Regulator issues a license within 80 working days of submission of the application.

• Market Rules10 are defined only for export. The rules require that the exporter sign contracts with a generation unit, EPSO, TSO, and Settlement Center similar to the model contracts set by the Regulator. More importantly, as previously mentioned, the rule defines that only Hrazdan Unit 5 or Hrazdan TPP can be exporting to generation units, taking into account the interests of internal customers.

• Rules for registering the contracts with the Regulator11 require that the applicant submit three copies of the contract, after which the Regulator checks their compliance with model contracts/ agreements,12 and, within 10 working days, registers it.

• Emergency situations are stated in the Energy Law as force majeure situations when the implementation of economic dispatch of the ordered reserve capacities is infeasible. Only newly adopted amendments to the Energy Law allow the export of electricity at a reasonable price and purchase from the DISCO during emergency situations. Moreover, they empower the Regulator to set the rules for electricity exchanges with other states during emergency situations and for power transits through the territory of Armenia. Being guided by the Energy Law, the Regulator recently adopted the Procedures for Export and Import of Electric Energy During Emergency Situations and Insuperable Force Events;13 according to which, electricity exchange functions are placed on the TO, while the ISO implements dispatching functions.

Being guided by the safety and reliability of the power system, the ISO makes decisions according to the situation, informing the TO, DSO, and Settlement Center.

• Transit is fixed by the Energy Law as transmission of the electric energy (capacity) through the customs territory of Armenia from entry to exit. Transit is regulated by the Energy Law and Customs Regulations Law as well by the secondary legislation. Legal acts and transit procedures were recently adopted by the Regulator.14 Transit through the territory of Armenia is implemented by the TO, while EPSO and the Settlement Center fulfill their own functions as usual. The TSO signs the agreements approved by the Regulator for transit operations with EPSO and the Settlement Center. Transit service payments for the TSO, EPSO, and the Settlement Center are also regulated by the transit procedures.

Finally, in summary:

• Licensing procedures take up to 80 working days, which is unreasonably long and generally makes it impossible to conduct effective, short-term (monthly, even seasonal) trade.

Required fees and guarantees can significantly influence the financial reasonableness of such contracts, especially in cases of limited import/export power flows.

• Market Rules allow export of electricity only from two TPPs: Hrazdan TPP and Hrazdan Unit5. The Hrazdan TPP, due to its low efficiency, is not able to provide competitive prices and, essentially, Hrazdan Unit5 is the only available exporting capacity.

10. www.arlis.am/DocumentView.aspx?DocID=96645.

11. www.arlis.am/DocumentView.aspx?DocID=85057.

12. www.arlis.am/DocumentView.aspx?DocID=86355.

13. www.arlis.am/DocumentView.aspx?DocID=96534.

14. www.arlis.am/DocumentView.aspx?DocID=100998.

http://www.arlis.am/DocumentView.aspx?DocID=96645 http://www.arlis.am/DocumentView.aspx?DocID=85057 http://www.arlis.am/DocumentView.aspx?DocID=86355 http://www.arlis.am/DocumentView.aspx?DocID=96534 http://www.arlis.am/DocumentView.aspx?DocID=100998

12 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

• The exporter needs to sign contracts at least with EPSO, TSO, and the Settlement Center.

There are no defined time limitations for these entities to sign such contracts, which create uncertain risks.

• The export/import contract becomes effective only after the Regulator’s registration and takes an additional 10 working days.

Basically, these regulations make the export/import possibilities significantly complicated and, therefore, require fundamental revision from the point of view of their usefulness as a regulatory tool.

3.5 STRUCTURE OF THE TARIFFS

All tariffs in the power sector are regulated, except for tariffs relating to export. The Regulator generally applies the rate of return methodology. All internal tariffs are recalculated on an annual basis. Incentive regulatory mechanisms are poorly structured.

The structure of tariffs is as follows:15

• Large generation tariffs are differentiated by capacity charge and energy price. The current average wholesale tariff, inclusive of Value Added Tax (VAT), is about 4.9 U.S. cents (¢) per kilowatt hour (kWh) (23.5 Armenian Drams (AMD)/kWh). The difference of monthly average generation prices is about 20 percent. During September and November, when the Armenian NPP is idle due to regular planned maintenance, the average generation price, inclusive of VAT, reaches about 7.1¢/kWh (35 AMD/kWh). However, this spread will change during the next two years due to the NPP rehabilitation plan. At that time, average generation prices will increase significantly.

• RE is regulated by a price cap tariff methodology with an annual recalculation formula that adjusts for inflation and exchange rates. Currently, PSRC has not yet set solar tariffs. It is expected to identify solar tariffs through tendering of solar photovoltaic (PV) projects under the World Bank Scaling-up Renewable Energy Program (SREP). It is expected this program will help finance the country’s first 40 to 50 MW of utility scale solar PV projects through private investors while minimizing the tariff impact by using SREP funds. The current tariff, inclusive of VAT, for small HPPs on drinking water pipelines is 2.6¢/kWh (12.6 AMD/kWh); on irrigation systems, it is 3.9¢/kWh (18.9 AMD/kWh); on water flows, it is 5.8¢/kWh (28.4 AMD/ kWh); and, for wind farms and biomass, it is 10.4¢/kWh (50.9 AMD/kWh).

• Transmission tariffs for wholesale market and export (although fixed on the same basis) are about 2.0¢/kWh (1.0 AMD/kWh) inclusive of VAT.

• EPSO and Settlement Center tariffs are defined as monthly service fees and as a separate electricity price for export.

• Distribution tariffs are not set yet. The absence of a proper legal framework artificially restricts consumers’ rights to import electricity from neighboring countries.

• End-user tariffs are differentiated by voltage levels for day and nighttime tariffs. There are no capacity charges, peak tariffs, or service fees. As a result, customers have no responsibility for defined capacity charges for large generation. End-user tariffs are among the highest in post-soviet union countries.16 For example, the household average tariff (day and night), inclusive of VAT, is about 9.6¢/kWh (47.0 AMD/kWh). Day and night tariffs

15. www.psrc.am/am/announcements/announcement/2142-1.

16. www.psrc.am/images/News/PSRC_Consulting_Services_Part_1_Report__ARM.pdf.

http://www.psrc.am/am/announcements/announcement/2142-1 http://www.psrc.am/images/News/PSRC_Consulting_Services_Part_1_Report__ARM.pdf for wintertime are set from 11:00 p.m. to 7:00 a.m. and, for summertime, from 10:00 p.m. to 6:00 a.m. Daily evening peak time during winter is from 7:00 p.m. to 9:00 p.m. and, during summer, from 9:00 p.m. to 11:00 p.m. The average difference between day and night tariffs for high voltage customers (35 to 110 kV) is only 12 percent and, for middle (6 to 10 kV) and low voltage (0.22 to 0.4 kV) customers, it is only 26 percent.

Although the Regulator applies the rate of return methodology, the cost of capital for government-owned companies is only 10 percent (before taxes, in local currency). All the major investments in these companies are made through “soft loans” with a government guarantee. Thus, the government-owned companies are not able to take advantage of commercial loans and operate as a standard commercial business unit.

3.6 FUTURE DEVELOPMENT PLANS

The GoA and MoENR, with the support of USAID,17,18 developed new Least-Cost Generation plans. On December 10, 2015, the GoA approved “long-term (until 2036) development perspectives of the energy sector of the Republic of Armenia,”19 which provides for the following:

• Rehabilitation of the Armenian NPP during 2017 and 2018 for a service lifetime extension up to 10 years and a rehabilitation cost of about $300 million.

It should be noted that the rehabilitation will allow not only extending the service lifetime of the Armenian NPP, but also bringing the operating 385 MW capacity closer to the installed 440 MW. As a result, the Armenian NPP, after rehabilitation, will be able to produce about 10 to 15 percent more electricity (250 to 350 GWh annually). The Armenian NPP tariff will significantly grow starting in 2019 to cover the investment costs of the rehabilitation.

• Construction of a new NPP unit with capacity up to 600 MW.

• The Hrazdan TPP is planned for decommissioning starting in 2019 due to its low efficiency.

It is planned to install one 240 MW new CCGT unit in 2019 and one 400 MW unit in 2022.

Those units will replace the Hrazdan TPP and will cover the contracted values of electricity-gas exchange agreements. However, the document assumes the final decision for the construction of a second 400 MW unit will be based on the economic indicators/growth of the gross domestic product, extension possibilities of the electricity-gas exchange contracts, and possibilities of economically reasonable import of electricity from Georgia.

The GoA, in November 2015, signed the memorandum of understanding (MOU)20 with Renco S.p.A on the construction of a new CCGT unit in Yerevan with 234 MW installed capacity and not less than 50.5-percent efficiency. The MOU obliged parties with several reciprocal responsibilities, among which the most significant are the following: power purchase guarantee for the produced electricity during the next 20 years (starting from the year of operation) given by the GoA, a 30-month period of construction, and a fixed 6.62¢/kWh without VAT price with an appropriate recalculation mechanism provided by Renco S.p.A.

17. http://leds.am/ss/USAID%20SUCCESS%20STORY_Strategy%20meeting.pdf.

18. http://leds.am/ss/USAID%20SUCCESS%20STORY_LCGP.pdf.

19. https://www.e-gov.am/protocols/item/582/.

20. https://www.e-gov.am/u_files/file/decrees/kar/2015/11/15_1364_1.pdf.

http://leds.am/ss/USAID%20SUCCESS%20STORY_Strategy%20meeting.pdf http://leds.am/ss/USAID%20SUCCESS%20STORY_LCGP.pdf https://www.e-gov.am/protocols/item/582%20/ https://www.e-gov.am/u_files/file/decrees/kar/2015/11/15_1364_1.pdf

14 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

During February 2016, the GoA, on the same basis, signed a second MOU21 with Grange Power LLC. A second CCGT unit, with the same capacity and efficiency factor, will be constructed in the Vanadzor, Lori region.

Neither of these decisions is final. During the next four months, companies will check the financial and technical feasibility of the projects and only then will the agreements be finalized.

• Three new large HPPs will be installed by 2036. The Loriberd HPP, with a planned capacity of 66 MW and annual production of 208 GWh, and the Shnogh HPP, with installed capacity of 70 MW and annual production of 270 GWh, will be in operation starting in 2022. In addition, the Megrhi HPP, with installed capacity of 130 MW and annual production of 800 GWh, will start operating in the system in 2034.

It should be noted that, for the construction of the Loriberd and Shnogh HPPs, the government is expected to involve private investments. At the same time, the government’s development plan for hydro energy22 suggests that the Regulator, starting in 2016, set up a price cap tariff for these HPPs on the level of 6.5¢/kWh without VAT. The expected investment costs for the Loriberd HPP is about $160 million and, for the Shnogh HPP, it is about $190 million. The construction period of such HPPs is about five years. Until now, there were no private investors involved in these projects, and it is necessary to assume that, more realistically, these two HPPs will not be operating in 2022. At the same time, it is questionable if the fixed tariff limitation will attract private investors.

The GoA, with USAID assistance, developed the Least-Cost Energy Development Plan (LCEDP) that, among other new generation options, also considered three new large HPPs.

The LCEDP provided data on capacity, efficiency, seasonal availability factors, annual maximum generation, investments, fixed and variable costs, and construction periods for the mentioned power plants. Under different scenarios, the energy sector expenditures, developments, swap, export and import options, etc., were analyzed.

• Renewable development is another important part of the development perspective. About 170 private, small HPPs (under 30 MW) are operating in the system with the installed capacity of 300 MW and annual generation of 700 GWh. About 45 small HPPs are under construction as of January 1, 2016, with a total capacity of 90 MW and annual generation of 315 GWh. Development perspectives set the target to construct up to 150 MW of small HPPs by 2021.

It is hard to foresee that another 60 MW of new small HPPs can realistically be constructed by 2021 because the economically attractive projects under the current tariff levels seem to be exhausted. In any case, it should be noted that the existing 170 small HPPs have a low capacity factor, 2,200 hours annually, when the projected capacity factor is about 2,800.

Finally, small HPPs will produce about 1,000 GWh annually, which can be increased up to 1,200 GWh when the operating small HPPs make new investments to improve their efficiency.

• The government plans to attract private investments for construction of 40 MW solar and 30 MW geothermal power plants from 2021 through 2024. Wind development is not highlighted in the program.

• The GoA is planning to finally renew the transmission system and increase transmission capacities. The long-term development program (until 2036) is envisioned to use several

21. https://www.e-gov.am/ajax/gfn.php?f=AKV-04-24-02.doc.

22. https://www.e-gov.am/u_files/file/decrees/arc_voroshum/09/qax35-12_1.pdf.

https://www.e-gov.am/ajax/gfn.php?f=AKV-04-24-02.doc https://www.e-gov.am/u_files/file/decrees/arc_voroshum/09/qax35-12_1.pdf loans for the rehabilitation of the transmission network; in particular, it is planned to use about $115 million of the International Bank for Reconstruction and Development (IBRD) loan and $23 million of the Asian Development Bank loan for renovation of 220 kV and 110 kV substations. In order to increase the reliability of the transmission network, construction is planned for six 220 kV and two 110 kV overhead lines financed by $39 million of the IBRD loan. About €11 million from the KfW Development Bank (KfW) loan will be used for rehabilitation of 220 kV and 110 kV overhead lines. Several loans and grants from KfW and the EU will cover the construction of the 400 kV Armenia-Georgia interstate transmission line with back-to-back (B2B) loan extensions until 2018, thus enhancing the regional integration of the Armenia power system.

• The market structure and future development of the tariffs are the next important part of the plan. The middle-term perspectives envision increasing liberalization of the Armenia power market in order to increase the efficiency and promote investments. To promote trade with Georgia, several new mechanisms will be needed such as transit, balancing, service provision, regulation of emergency supplies, and inadvertent power flows. The revision of the tariff methodology with the introduction of more efficient seasonal and hourly tariff structures is also part of the middle-term market reforms. All aforementioned activities are planned for the period 2016 through 2019.

• The development of this infrastructure is expected to increase tariffs by about 1.1¢/kWh (5.5 AMD/kWh) and will reach its maximum during the 2020-2021 period.

3.7 TRANSMISSION DEVELOPMENT IMPACT ON CROSS-

BORDER TRADE

Armenia has had a reliable transmission infrastructure since Soviet times. During the last few years, one 220 kV interconnection was put into operation and a number of high-voltage substations were reconstructed. In 2015, the transmission tariff, inclusive of VAT, was set at 0.2¢/kWh (1.0 AMD/kWh). The construction of new interconnections will significantly influence transmission costs. These interconnections will serve almost entirely export/import operations, but they increase reliability of supply for internal customers. For cross-border trading, an appropriate infrastructure is needed, and it should be developed strictly in accordance with technical capacities and economic feasibility. Otherwise, this will hinder the development of international trade and will increase the financial burden on the domestic consumers.

16 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

Armenia and Georgia are interconnected with 1) 220 kV Alaverdi-Gardabani, 2) 110 kV Ashotsk- Ninotsminda, and 3) 110 kV Alaverdi-Sadakhlo lines (Figure 1).

Figure 1. Armenian Interconnections

In today’s situation, Georgia is synchronized with Russia, and Armenia is synchronized with Iran.

Only asynchronous operation between Armenian and Georgian power systems or operation in island mode can be realized. Operation in island mode cannot ensure significant electricity flow (possibly up to 40 MW). Because this situation is unlikely to change in the near future, the option of parallel asynchronous operation of the Armenian and Georgian power systems through B2B converters has been chosen as a feasible option.

This project will achieve an asynchronous power connection between Georgia and Armenia and thereby closing a missing link for a reliable, flexible, and mutually profitable cross-border trade. In addition, the project improves the country’s energy infrastructure, facilitates energy security, and enhances power export and transit potential.

The project aims to connect the Armenian and Georgian power grid via a 500/400/220 kV B2B station with a final capacity of 1,050 MW in Ayrum (Armenia), close to the Georgian border. The connection from the Georgian side will be via a 500 kV line from the substation Marneuli (not part of the project) and the connection from the Armenian side via a 400 kV line from Hrazdan (at the first stage via the existing 220 kV line from Alaverdi). The overall project will be carried out in three subsequent stages with construction of transmission infrastructure and 350 MW B2B units during each stage. After the implementation of the first stage, the maximal transfer capacity will reach about 200 MW. The design of the project is based on the Prefeasibility Study of February 2013 as well the Feasibility Study of February 2014 carried out by the consulting company Fichtner. The estimated project cost for Stage 1 is approximately €188 million, supported by different KfW soft loans, with a grace period of 5 to 10 years. The final decision for the next two stages will depend on real power exchanges and trade opportunities through the new transmission infrastructure.

If the Regulator continues applying the same methodology of sharing development costs between power flows of the internal market and possible export/import, including transit flows, the transmission tariff on average will increase about three times compared with 2015. Future levels of the transmission tariff will be very sensitive to the volume of external flows, and projected power flows will influence affordability of the transit and cross-border trade. The current tariff methodology applied by the Regulator provides a more reasonable regime for transit and cross-border trade because internal market participants will cover some part of the development costs.

18 ARMENIA GAP ANALYSIS WITH LIST OF MARKET CHALLENGES AND LEGAL BARRIERS

4. SITUATION IN THE

POWER MARKET OF

GEORGIA

4.1 DOMESTIC MARKET PRINCIPLES AND CROSS-BORDER

TRADE

According to current power Market Rules, the licensed carriers of the power sector make short-term (one year) or long-term (five years) contracts on sales and purchases. The contracts are made between the customer and the producer, while the contract on the balance capacity purchase is made with the commercial operator. The purchaser is obliged to have reserve power amounting to 10 percent of its utilized power (a minimum 5 percent of this amount should be supplied by local sources) to ensure energy security of the country. It is possible to supply the reserve power by direct contract, private sources, or commercial operator.