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ENERGY SECTOR OVERVIEWCHARGING FORWARD

JULY 2019

GIVI ADEISHVILI

+ (995 32) 2 27 27 27 [email protected] www.tbccapital.ge www.tbcresearch.ge

TABLE OF CONTENTSEXECUTIVE SUMMARY 5

GEORGIA’S ELECTRICITY SECTOR 6

GENERATION AND CONSUMPTION: DEMAND HAS EXCEEDED DOMESTIC SUPPLY SINCE 2017 6

TRANSMISSION AND DISPATCH: ESTABLISHING GEORGIA AS A REGIONAL TRANSIT HUB 10

DISTRIBUTION: DUOPOLY MARKET 14

PROJECT PIPELINES AND PROJECTIONS FOR GENERATION AND CONSUMPTION UP TO 2023 17

HPPS: SOURCE OF GROWTH IN ELECTRICITY GENERATION FROM RENEWABLES 17

PROJECTIONS IN GENERATION AND CONSUMPTION: IMPORTS WILL BALANCE THE INCREASING DEFICIT 18

DEREGULATION AND MARKET DEVELOPMENT 21

EU 3RD ENERGY PACKAGE AND A NEW ENERGY LAW IN GEORGIA 21

ELECTRICITY TRADING MECHANISMS (ETMS) AND THE MARKET MODEL 24

IMPACT OF REGULATION ON ELECTRICITY PRICES AND THE INVESTMENT ENVIRONMENT 27

GLOBAL ELECTRICITY MARKET TRENDS 30

ENERGY SOURCES GLOBALLY: SOLAR AND WIND POWER ARE ON THE RISE 30

GREEN ECONOMY: A TECHNOLOGY-BASED INDUSTRY 31

RENEWABLES IN GEORGIA 34

HYDRO, WIND AND SOLAR: BROADLY UNTAPPED POTENTIAL 34

GREEN BONDS AND RENEWABLE FINANCING: AN OPPORTUNITY FOR THE PRIVATE AND PUBLIC SECTORS 36

POWER SECTOR RISKS: UPSIDE FROM A FIXED PRICE AND ABOLISHMENT OF PPAS 38

ANNEX 39

FORMING A FULLY COMPETITIVE MARKET: 39

ACCRONYMS AND ABBREVIATIONS 41

DISCLAIMER 43

EXECUTIVE SUMMARY

Electricity consumption is growing faster than generation in Georgia. Consumption has grown at a 5% CAGR over the past six years to 12.6 TWh in 2018, while generation increased at a 3.8% CAGR to 12.1 TWh. The hike in electricity demand has resulted in higher net imports, which grew 13% y-o-y in 2018 to 0.9 TWh. Lack of water resources decreased generation to 6.2 TWh in 1H 2019, down by 2.1% y-o-y, leading to increased net imports of 0.4 TWh, up by 185% in the same period.

Cryptocurrency mining and growth in tourism boosted electricity consumption in 2016-2018. Consumption by household and commercial users grew at a 6.1% CAGR over two years to 8.9 TWh in 2018, whilst consumption by eligible consumers (mostly cryptocurrency mining companies) grew at a 22% CAGR to 1.8 TWh. Electricity consumption of tourism and large companies mining cryptocurrency accounted for 10% of total consumption in 2018.

A dearth of generation capacities are expected to hike electricity imports. TBC Capital projects a 5.1% annual increase in electricity consumption in Georgia over the next five years to 16.1 TWh by 2023. An expected slowdown in cryptocurrency mining will be offset by increased tourism and growing production in the following years. Generation is expected to grow at a 4.1% CAGR to 14.8 TWh until 2023 and 1.9 TWh of net imports will be required to meet the expected shortfall in generated electricity.

Increasing demand for electricity, the potential for market deregulation and growth in electricity prices form the investment story for Georgia’s electricity sector. In 2019-2022, 25 HPPs with installed capacity more than 610 MW, annual generation of 2.3 TWh and total investment exceeding USD 1 bn are scheduled to be completed. However, up to 1,000 MW of additional hydropower capacity is required to satisfy the increasing domestic consumption by 2023.

Downside risks raise uncertainty for the investment outlook. The main challenges facing Georgia’s electricity sector include the abolishment of price-hedge PPAs, delays in deregulation, problems with HPP construction, and electricity price fluctuations in Turkey as the main export market. We believe that additional incentives will be needed to attract investment into new generation capacities and underpricing the electricity could deter investments and worsen customer conditions in the longer term.

Risks of the electricity supply interruptions are moderate. Domestic producers satisfy over 90% of Georgia’s electricity demand. However, Enguri HPP’s high market share (33%) decreases supplier diversification. The plant is not expected to be decommissioned, but ongoing repair works and problems with the Abkhazeti breakaway region are creating issues in generation and in the security of supply. The construction of new capacities will decrease share of Enguri HPP to 28% by 2023 and increase supplier diversification.

Increasing demand for electricity and lack of sufficient generation capacity are expected to create upward pressure on prices. Infrastructure investments will also contribute to the price increase. However, the average price increase should be moderate, partly because the future market model will maintain a regulated portion alongside the deregulated part.

Stakeholders are expected to benefit with the implementation of new Electricity Trading Mechanism. Although employee training and integrating new technology will bring new costs, market participants will benefit from the free market and improved quality of service. There is no guarantee of lower electricity prices after market liberalization, but a more open market leads to better investment incentives and improved service quality.

5ENERGY SECTOR OVERVIEW CHARGING FORWARD

GEORGIA’S ELECTRICITY SECTOR

The electricity sector is a key driver of the Georgian economy with its strengths rooted in country’s ample hydropower resources. With largely liberal but regulated market standards already in existence, Georgian electricity sector is entering a phase of free trading and further deregulation. We start our report by providing a snapshot of overall market structure, future outlook of market development and conclude with our thoughts on deregulation, opportunities and further steps towards financing the green economy.

GENERATION AND CONSUMPTION: DEMAND HAS EXCEEDED DOMESTIC SUPPLY SINCE 2017

Renewable energy potential in Georgia provides the unique opportunity for electricity generation. Currently, less than half of the country’s economically feasible hydro energy potential is utilized. Despite a continuous increase in electricity generation in recent years, consumption has surpassed domestic supply since 2017, turning Georgia into net importer of electricity.

Annual electricity generation grew at a 3.8% 6-year CAGR to 12.1 TWh in 2018. Over that same period, consumption increased at a 5% 6-year CAGR to 12.6 TWh. Supply and demand imbalances increased net import to 0.9 TWh for the same period. This year (as of 1H 2019), generation has decreased 2.1% y-o-y to 6.2 TWh, leading to 185% growth in net imports to 0.4 TWh.

FIGURE 1: ELECTRICITY GENERATION AND CONSUMPTION (TWH) IN GEORGIA

Source: Electricity System Commercial Operator (ESCO)

Largest consumers of Georgian electricity market could be classified as: Distribution System Operators (DSOs), eligible consumers and region of Abkhazeti.

• DSOs (household and commercial end-users) increased electricity consumption at a 6% 6-year CAGR to 8.9 TWh in 2018. Tourism was one of the drivers for the increased electricity consumption in the country. Number of international visitors grew at an 11.9% CAGR to 8.6 mln, over the same period. In addition, small-scale cryptocurrency mining has contributed to the consumption increase over the last several years.

6 ENERGY SECTOR OVERVIEW CHARGING FORWARD

• Consumption by eligible consumers has grown at a 2.1% 6-year CAGR to 1.8 TWh in 2018. Cryptocurrency mining companies, which were registered as eligible consumers in 2H 2018 and consumed 0.4 TWh of electricity thereafter in 2018, were major drivers of the growth. Excluding the cryptocurrency miners, electricity consumption by eligible consumers decreased to 1.4 TWh, down by 13% for the 6-year period.

• In 2018, approximately 48% of electricity generated by Enguri HPP and 16% of total generated electricity in Georgia was delivered to the breakaway region of Abkhazeti. The consumption of electricity in the region has been growing at a 3.8% 6-year CAGR and reached 1.9 TWh in 2018.

In 1H 2019, Georgia’s electricity consumption growth slowed to 1.9%. Region of Abkhazeti displayed substantial growth at 10.3%, while demand increased by 0.3% y-o-y in the rest of the country.

FIGURE 2: LARGEST CONSUMERS (TWH) OF THE GEORGIAN ELECTRICITY MARKET

Source: ESCONote: * Kakheti Energy Distribution was acquired by EPG in 2017

Overall, electricity consumption of the largest cryptocurrency mining companies accounted for an estimated 7% of total consumption in 2018. However, the number should be higher considering small mining companies and individual households mining the cryptocurrency. The future of the cryptocurrency market is hard to predict, but with crypto prices falling by the end of 2018 and in the beginning of 2019, electricity consumption slowed down in industry.

In 2018, seven regulated hydropower plants (HPPs) with 1,993 MW of installed capacity, 16 seasonal and 57 small capacity HPPs (860 MW and 194 MW), five Thermal Power Plants (TPPs, 924 MW) and a single wind power plant (WPP, 21 MW) with total installed capacity of 3,992 MW were operating in Georgia. Renewable energy accounted for 78% of the country’s total installed capacity and HPPs and the one WPP accounted for 83% of generated electricity in Georgia. Early in 2019, two seasonal HPP (Mestiachala HPP 1&2) and one small HPP (Orozmani HPP) launched generation activity.


FIGURE 3: SHARE OF POWER PLANTS BY INSTALLED CAPACITIES1 (MW) AND ANNUAL GENERATION (TWH) IN 2018

Source: ESCO, TBC Capital

KEY PLAYERS IN GENERATION

The electricity generation market is moderately concentrated, while 94% of installed capacity is distributed between eight players. Those eight are:

• State-owned: Enguri HPP (1,300 MW) and Vardnili HPP (220 MW). The Enguri HPP dam is located on territory controlled by Georgia, while the powerhouse is located in the breakaway region of Abkhazeti. In 2018, the Enguri and Vardnili HPPs together generated 4.8 TWh, 39% of all electricity generated in Georgia.

• Georgian Industrial Group (GIG): GIG owns and operates HPPs, TPPs and a Coal Power Plant with total installed capacity of 662 MW. GIG is also electricity trader, handling exports, imports and transit of electricity.

• Energo-Pro Georgia (EPG): EPG is part of the Czech-domiciled Energo-Pro Group. EPG generates and distributes electricity. It owns HPPs with combined installed capacity of 482 MW, as well as a 110 MW open cycle gas turbine.

• Georgian Oil and Gas Corporation (GOGC): The Ministry of Economy and Sustainable Development (MOESD) established GOGC in 2006. The company owns Gardabani TPP (231 MW) and Kartli Wind Farm WPP (21 MW).

• Georgian Global Utilities (GGU): GGU owns the leading water supplier Georgian Water and Power (GWP). The company supplies water to Tbilisi and to state-owned organizations and business. GWP owns and operates Zhinvali HPP (130 MW) and other small HPPs with total installed capacity of 150 MW. In addition, two new HPPs (Mestiachala HPP 1 and Mestiachala HPP 2) with total installed capacity of 50 MW where commissioned in 2019 under GGU.

• Telasi: Telasi is a subsidiary of Russian energy conglomerate Inter RAO (75%) and the state-owned Partnership Fund (25%). Apart from distributing electricity in Tbilisi, Telasi owns and operates Khrami 1 HPP (113 MW) and Khrami 2 HPP (110 MW).

1 Data excludes installed capacity of Shuakhevi HPP (178 MW), which is on the rehabilitation stage


• Georgian American Alloys (GAA): GAA is headquartered in Miami and manufactures and supplies ferroalloys for iron and steel production. The company owns Georgian Manganese Mine and Vartsikhe HPP (184 MW).

• Peri: Peri is a company domiciled in Georgia, with major focus on design and construction of HPPs. The company has experience in construction of pipelines, dams and sewerage systems. Peri owns and operates HPPs with cumulative installed capacity of 144 MW.

FIGURE 4: INSTALLED CAPACITIES (MW) BY KEY PLAYERS’ AND THEIR MARKET SHARE IN 1H 2019

Source: ESCO, TBC Capital

The electricity generation tariffs for regulated HPPs range from GEL 0.016 to GEL 0.041 per KW. The tariffs for TPPs are from GEL 0.08 to GEL 0.12. In addition to the price for generated electricity, TPPs receive compensation as a guaranteed capacity fee to cover fixed costs. The daily compensation for the guaranteed capacity fee and the number of compensable days is regulated by the Georgian National Energy and Water Supply Regulatory Commission (GNERC).


SEASONALITY

The high share of HPPs in total generation and fluctuation of water resources during the year leads to the seasonality in electricity supply. The generation surpasses the local demand during the summer periods and deficit occurs in the winter months.

FIGURE 5: SEASONALITY OF CONSUMPTION AND GENERATION (TWH) IN GEORGIA IN 2018

Source: ESCO

Electricity consumption is higher in the winter. According to a study by Georgia’s National Statistics Office (GeoStat), 6.5% of households use electric appliances for heating and 80%2 of all bulbs are energy inefficient incandescence bulbs, which increases demand for electricity.

Besides the winter months, summer peaks are also driving increased consumption. In 2018, high temperatures in the summer increased air conditioning use, which pushed total electricity consumption to a record high. We expect that depicted high consumption growth of electricity in the summer months will flatten the demand for electricity in the future.

Overall, generation capacities are falling short of the growing consumption, and additional generation assets will be needed. We believe additional incentives will be needed to attract investment into new generation capacities. And on the other hand, underpricing the electricity by regulator could deter investments and lead to a deterioration of conditions for customers in the longer term.

TRANSMISSION AND DISPATCH: ESTABLISHING GEORGIA AS A REGIONAL TRANSIT HUB

Georgia’s electricity grid is connected to neighboring countries Russia, Azerbaijan, Armenia, and Turkey. Cross-border trade allows Georgia to balance the seasonality in its electricity generation sector. Electricity is exported in the surplus months (April-August) and imported during periods of deficit. Over the past 6 years, imports grew 2 Energy Consumption in Households: GeoStat (2017)


at a 16% CAGR to 1.51 TWh in 2018, while exports have remained unchanged at 0.59 TWh, meaning that generation lags consumption growth. To balance generation shortfall in 1H 2019, net imports increased to 0.39 TWh, up by 185% y-o-y.

Electricity imports from Azerbaijan have risen sharply since 2016 and accounted for 82% (1.23 TWh) of total imports in 2018. Low import price (USD 0.052) is the main reason for the increasing electricity imports from Azerbaijan. The growth in Azerbaijan’s share has continued in 2019. In 1H 2019, 88% of imports came from Azerbaijan and 12% came from Russia. The electricity imported from Russia was used to meet the increasing electricity demand in the Abkhazeti region.

FIGURE 6: ELECTRICITY TRADE WITH NEIGHBORING COUNTRIES (TWH)

Source: ESCO

In 2018, Turkey (66%) was Georgia’s key export market, followed by Russia (16%) and Armenia (14%). High electricity prices in Turkey were the main driver of electricity exports. However, the greater than 100% depreciation of the TRY against the USD over the last four years has caused electricity market clearing prices in Turkey (average over April-August) to decrease at a 12.2% 4-year CAGR to USD 0.0458 in 2018. Commissions and other cross-border trade fees between Georgia and Turkey further decrease the electricity export price. Overall, Georgian generation companies receive on average a 40% lower price than the market clearing price in Turkey.

In contrast, ESCO’s electricity balancing price in Georgia has increased at a 9.3% 4-year CAGR to USD 0.0478 over that same period. ESCO holds an average 30% share of the electricity trade (balancing electricity) and the increase in the electricity price represents an opportunity to catch up with Turkey’s market clearing price. Export in Turkey is an option for the Georgia’s deregulated power plants. In 2018 ESCO electricity purchase price for the deregulated power plants accounted for USD 0.007 during the summer months, but it should be mentioned that it was the lower price bound and most of the deregulated power plants arranged to sell electricity via direct contracts with a higher price, which was close to the export price in Turkey.


FIGURE 7: ELECTRICITY MARKET CLEARING PRICE IN TURKEY, EXPORT NET PRICE OF GEORGIAN ELECTRICITY TO TURKEY AND ESCO BALANCING ELECTRICITY PRICE (USD cents, AVERAGE OVER APRIL-AUGUST)

Source: EPIAS, ESCO, TBC Capital

Transmission System Operators (TSOs) receive a fixed price set by the GNERC for transferred electricity. That price varies based on their investment in infrastructure and operating costs. The GNERC accepts transmission losses of 2%, with amounts above that excluded from the tariff calculation. The total transmission tariff in Georgia increased to GEL 0.0198/KWh in 2018, up 38% y-o-y. That is still low relative to the EU single market’s average EUR 0.012/kWh3 (GEL 0.0326) – 59% for infrastructure costs, 31% for system service, and 10% for losses.

TABLE 1: TRANSMISSION AND DISPATCH TARIFFS (GEL TETRI PER KWH) IN GEORGIA

Source: GNERC

3 Overview of Transmission Tariffs in Europe: ENTSO-E (2018)

Entity Functions 2017 (GEL TETRI) 2018-2020 (GEL TETRI) Change

Georgian State Electrosystem (GSE)

DispatchTransmission

0.0820.872

0.4121.323

402%52%

Sakrusenergo Transmission 0.180 0.278 54%

EnergotransTransmission, 500 kV

Transmission, 400 kV0.3870.496

0.3800.380

(2%)(23%)

TotalDispatchTransmission

0.0821.439-1.548

0.4121.981

402%33%


Transmission tariffs are the main revenue component for TSOs. Their Weighted Average Cost of Capital (WACC) increased to 16.4%4 in 2017, from the 13.5% rate set previously. Depreciation of GEL against USD was the main driver for the increased WACC. TSOs can generate additional revenues via transit, but the transit of electricity was low over the last three years: 1.1 TWh in 2016-2017 (mainly from Azerbaijan to Turkey) and 0.013 TWh in 2018.

TSOs must develop 10-year plans that will support the integration of electricity generating power plants into the network and increase cross-border capacities. In 2019, GSE identified the Jvari-Tskaltubo-Akhaltsikhe and Jvari-Khorga internal lines and the Ksani-Stepantsminda-Mozdok cross-border line as priority transmission lines. These lines will integrate more than 3,200 MW of hydropower into the grid and improve the reliability of parallel operations with the Russian power system.

TABLE 2: GEORGIA’S CURRENT AND PROJECTED TRANSMISSION LINES WITH NEIGHBORING SYSTEMS

Source: GSE

Overall, increased electricity consumption and the seasonality in generation have doubled the annual trade volume to 2.1 TWh in 2018 compared to 2012. The existing transmission network has sufficient capacities to meet current needs. However, it will require investment as trade and transit volumes grow and as new generation capacities come online. The GSE is slated to invest more than GEL 2.2bn5 in infrastructure by 2023 and the transmission tariff is expected to exceed GEL 0.0266 by then.

Bordering country

Cross-border line Voltage (kV) Exchange Capacity (MW) Operation

date

Armenia AlaverdiMarneuli

220400

Export / ImportExport / Import

150 / 100700

Operational2025

AzerbaijanMukhranis VeliGardabani

500330

Export / ImportExport / Import

700670

Operational2022

Russia

KavkasioniKsani-Stepantsminda-MozdokSalkhino

500

500

220

Export / Import

Export / Import

Export / Import

610

1,000

50 / 150

Operational

2023

Operational

Turkey

MeskhetiAkhaltsikhe-Tortumi

Batumi-Muratli

Adjara

400

400

154

220

Export

Import

Export / Import

Export / Import

1,050

350

350

150

Operational

2022

2025

Operational

4 The GNERC has determined WACC for a three year period in 2017 5 GSE 10-year plan 2019-2029 6 TBC Capital Research


DISTRIBUTION: DUOPOLY MARKET

TSOs transfer electricity from generation companies to DSOs (Telasi and EPG), which deliver it to final consumers. Total number of electricity consumers in Georgia grew at a 2.2% 7-year CAGR to 1.77 mln in 2018. Household consumers accounted for 94% of total and commercial consumers – 6%, respectively. Telasi covers 0.57 mln consumers (electricity consumption – 3.0 TWH) in Tbilisi municipality and EPG covers the rest of Georgia (excluding the breakaway regions of Abkhazeti and Samachablo) – 1.2 mln of consumers (electricity consumption – 5.9 TWH).

Currently, electricity distribution and supply are not separated, thus households and commercial users cannot switch suppliers. In contrast, eligible consumers buy electricity directly from the electricity generating units, without involvement of DSOs. Besides distribution, Telasi and EPG generated 0.5 TWH and 1.8 TWH of electricity in 2018, respectively. Their total annual revenues reached GEL 1,133mln in 2017: GEL 439mln for Telasi and GEL 694mln for EPG.

Supported by the growing demand and stable population, per-capita electricity consumption in Georgia has increased at a 5.4% 6-year CAGR to 2,870 kWh in 2018. That is still half the EU average of 5,392 kWh, but higher than that of neighboring Armenia and Azerbaijan.

FIGURE 8: ANNUAL PER CAPITA ELECTRICITY CONSUMPTION7 (KWH) IN 2016 (Georgia: 2018)

Source: IEA, ESCO, Eurostat, TBC Capital

We expect the country’s growth and its increasing tourism will drive higher consumption. Besides adding generation capacities, promoting energy efficiency can be a cost-effective solution to slowing the growth in demand. An increase in the electricity tariff could also stimulate the development of energy-efficiency initiatives.

7 Data for Georgia excludes the Abkhazeti region


TARIFFS

The GNERC regulates the electricity retail market and determines rates for households and commercial consumers. The price of electricity depends on consumption volumes, ranging from GEL 0.14/kWh to GEL 0.23/kWh for households and from GEL 0.15/kWh to GEL 0.21/kWh for commercial users. Electricity production costs for TPPs are indirectly subsidized by Georgian Oil and Gas Corporation (GOGC).

Household electricity prices in Georgia are higher than in Azerbaijan and Russia, but lower than in Armenia and Turkey. Energy-rich countries can subsidize electricity rates by providing natural gas to TPPs. The difference in household electricity prices between Georgia and its neighbors also reflects trade patterns. Turkey is the main export market for electricity, while imports from Azerbaijan are used to balance shortfalls in the winter months.

The average household electricity price in Georgia is nearly three times lower than in the EU. Taxes and fees are key drivers of the difference; they account for an average 58% of the rate in the EU compared to 18% in Georgia. Renewable energy subsidies are a main driver of the high electricity taxes and fees in the EU. EU member states collected EUR 280bn8 in energy taxes in 2016, while renewable energy subsidies reached EUR 76bn in that year.

FIGURE 9: ELECTRICITY PRICES FOR HOUSEHOLDS (EUR PER KWH) IN 2018

Source: Eurostat, GNERC, TBC Capital

8 Energy Prices And Costs In Europe: European Commission (2018)


The household electricity consumption tariff in Georgia is shared between generation companies (48%), ESCO (0.1%), TSOs (10%), the dispatch center (2%), DSOs (25%), and the government (15%, taxes). Generation companies receive the highest share and taxes include only Value Added Tax (VAT), which increases the electricity price by 18% (15% of the total).

TABLE 3: COMPOSITION OF AVERAGE HOUSEHOLD ELECTRICITY TARIFF IN GEORGIA IN 2018

Source: GNERC, TBC Capital

EU countries are increasing electricity tax rates as a way to decrease consumption and to promote energy efficiency and investment in renewables. Over time, we expect price regulation in Georgia to be modified to accommodate the increasing need for additional capacity and clean energy.

Overall, the electricity distribution market is a duopoly, with two companies (Telasi and EPG) sharing 25% of the final price of electricity to households. The Association Agreement with the EU requires separating supply and distribution functions and enabling supplier switching. Deregulating power distribution and increasing market competition would help enshrine a market-based price environment.


PROJECT PIPELINES AND PROJECTIONS FOR GENERATION AND CONSUMPTION UP TO 2023

HPPs: SOURCE OF GROWTH IN ELECTRICITY GENERATION FROM RENEWABLES

FDI into Georgia’s energy sector peaked in 2007 and 2008, reflecting a liberal government policy and growing energy prices. In the years that followed, FDI fluctuated as investor uncertainty rose. In 2018, FDI into energy dropped 30% y-o-y to USD 157 mln. In Q1 2019, FDI into the sector fell to USD -9mln , possibly due to the abolishment of Power Purchase Agreements (PPAs) and overdue of the sector deregulation.

FIGURE 10: FDI IN ENERGY (USD mln) AND SHARE IN TOTAL (%) IN GEORGIA 2007-2019

Source: GeoStat

Prior to 2018, the government offered PPAs to HPP developers, according to which purchase prices for generated electricity were pre-determined. The incentive acted as a price hedge and helped attract investment. From 2018, the government abandoned the previously practiced approach, most probably due to the expected sector deregulation. The HPP projects planned prior to the abolishment of the PPAs had supported FDI in the sector. Without the guaranteed purchase price, generation companies are exposed to price fluctuations, and the lack of PPAs is likely to negatively affect FDI in the coming years.

Construction cost of run-of-the-river HPP in Georgia ranges from USD 1.2mln to USD 1.5mln per MW, based on the specific project. Over the last four years, more than 20 HPPs and one wind farm were built in Georgia. Those projects cost more than USD 400mln and brought 327 MW of total installed capacity and 1.5 TWh of annual generation. The new HPPs increased electricity generation to 12.1 TWh in 2018.

In addition to the PPAs, price fluctuations in Turkey (the main export market), delays in establishing a new electricity market framework, and construction problems with HPPs (Khudoni and Namakhvani) and transmission


lines are key obstacles that have negatively impacted investor expectations and could reduce investment into the electricity sector.

On the other hand, increasing demand for electricity, coming market deregulation, and an expected increase in electricity prices create upside for investment into the sector. Over 2019-2022, 25 HPPs with installed capacity more than 600 MW, annual generation of 2.3 TWh and total investment of more than USD 1bn are scheduled to be completed.

TABLE 4: EXPECTED ANNUAL GENERATION (TWH) FROM NEW HPPs IN GEORGIA 2019-2022

Source: MOESD, TBC Capital

PROJECTIONS IN GENERATION AND CONSUMPTION: IMPORTS WILL BALANCE THE INCREASING DEFICIT

We project annual electricity generation growth at 4.1% over the next 5 years to 14.8 TWh in 2023. That projection is based on the three main generating sources: hydro, thermal, and other renewables.

• Planned and under construction HPPs will be the main contributors to the growth; electricity production from HPPs is expected to grow 4.2% annually to 12.2 TWh.

• TPPs are expected to increase production 3.4% annually to 2.5 TWh by the end of 2023. Production of electricity by natural gas with high commercial price is not cost-effective alternative to the imported electricity and utilizing potential of Shah Deniz pipeline is expected to increase supply of subsidized natural gas to TPPs.

• Wind-based renewable energy generation is projected to remain steady at 0.1 TWh as there are currently no new projects planned to be completed until 2022. However, even new wind or solar projects are unlikely to materially change the overall amount of electricity generated because the new projects would likely represent limited capacity.


FIGURE 11: PROJECTED ELECTRICITY GENERATION (TWH) BY SOURCE IN GEORGIA9

Source: MOESD, TBC Capital

Electricity consumption has been very sensitive to Georgia’s economic booms and downturns over 2008-2018. Consumption growth and real GDP growth have been highly cyclical, with a correlation between the two of greater than 84%.

FIGURE 12: ELECTRICITY CONSUMPTION10 AND REAL GDP GROWTH (%)

Source: ESCO, GeoStat, TBC Capital

9 Assuming no decommissioning of existing installed capacity10 Excluding electricity consumption in the Abkhazeti region


The high correlation between economic growth and electricity consumption should continue in the coming years. The International Monetary Fund (IMF) projects on average 5.0% economic growth over the next five years, which should result in similar growth in electricity consumption.

We see electricity consumption growing 5.1% annually over the next 5 years to 16.1 TWh in 2023. Growth is supported by increasing tourism and slowdown in the crypto mining industry creates downward pressure on consumption.

• We assume that large cryptocurrency mining companies will sustain current consumption level at 0.9 TWh for the forecasted period. In 2018, large cryptocurrency mining companies were operating near breakeven profits levels, whereas the price of Bitcoin fell to near its mining cost11 (USD 2,900-3,300) before recovering somewhat in 2019.

• Annual consumption by large industrial consumers is projected to increase by 4.2% annually to 3.2 TWh in 2023. Expected economic growth and higher production levels is expected to be key contributor to growth.

• The Abkhazeti region is projected to continue growing consumption at 4.2% annually (the same trend it maintained over 2008-2018).

• Electricity consumption of households and commercial users is projected to grow 5.9% annually, slightly slower than the 6.5% annual average growth in 2008-2018. Increasing tourism creates upside for consumption by households and commercial users. We estimated net effect of tourism to reach 5% (0.7 TWh) of total consumption in 2023, compared to 3% (0.3 TWh) in 2018. On the other hand, a slowdown in the crypto mining sector will decrease electricity consumption by households and small mining companies, whose production costs are higher than those of large cryptocurrency producers.

FIGURE 13: PROJECTED ELECTRICITY CONSUMPTION (TWH) IN GEORGIA

Source: ESCO, TBC Capital11 TBC Capital estimates.


Overall, electricity generation is projected to grow at a slower pace than consumption, with a net deficit of 1.3 TWh as of 2023. The shortfall will be covered by net imports of more than 1.9 TWh in 2023 (considering losses and transmission costs).

DEREGULATION AND MARKET DEVELOPMENTEU 3RD ENERGY PACKAGE AND A NEW ENERGY LAW IN GEORGIA

The EU liberalized its electricity market by introducing Directive 96/92/EC on the common rules for the internal electricity market in the 1990s, Directive 2003/54/EC enabling suppliers to enter EU member countries, and Directive 2009/72/EC, commonly known as the 3rd Energy Package, which established common rules for the generation, transmission, distribution and supply of electricity in the EU. The 3rd Energy Package directive includes the following rules:

• All customers should have access to electricity regardless of the supplier’s member state, as long as the supplier follows applicable trading and balancing rules.

• Customers must be able to switch suppliers.

• Electricity projects should strive to be energy-efficient by providing energy management services, developing innovative pricing mechanisms, and introducing intelligent metering systems and smart grids.

• A single point of contact will provide consumers with all the necessary information regarding their rights, current legislation, and dispute settlement means available to them in the event of a dispute with their electricity supplier.

• The energy ombudsman or a similar consumer body should be established to ensure the efficient treatment of complaints and out-of-court settlements.

Georgia signed an Association Agreement with the EU in June 2014. Under the agreement, Georgia is to bring its legislation in line with EU legislation; that includes the 3rd Energy Package. In October 2016, Georgia joined the European Energy Community and agreed to implement the following directives and regulations in the electricity sector:

TABLE 5: ENERGY DIRECTIVES AND REGULATIONS

Source: EUR-Lex, MOESD Note: * Due dates can be reviewed and can include a possible 12-month grace period. An extension for the implementation of directives can be further permitted if the Georgian government requires more time.

DIRECTIVE 2009/72/EC Rules for the electricity market 31.12.2018REGULATION 714/2009 Cross-border trade in electricity 31.12.2018DIRECTIVE 2005/89/EC Security of electricity supply 31.12.2019DIRECTIVE 2009/28/EC Renewable energy 31.12.2018DIRECTIVE 2012/27/EU Energy efficiency 31.12.2018DIRECTIVE 2010/31/EU Energy efficiency of buildings 31.12.2019DIRECTIVE 2008/92/EC Transparency of gas and electricity supply 31.12.2017REGULATION 1099/2008 Energy statistics 31.12.2017

Energy directives and regulations Due Date*


EU Directive 2009/72/EC defines TSOs as grid owners and proposes an unbundling of that ownership by separating the assets of the TSOs or transforming them into Independent System Operators (ISO), if it is part of a vertically integrated structure. Under that directive, Georgia must make a public service obligation (PSO) to customers to ensure a regular supply of electricity and to nominate a “supplier of last resort”.

REGULATION 714/2009 on the conditions for access to the network for cross-border exchanges of electricity between Georgia and EU member states is possible with the involvement of Turkey as an intermediary trading partner.

DIRECTIVE 2005/89/EC obligates states to safeguard the security of continuous electricity supply and infrastructure investment, take measures to facilitate a stable investment climate, ensure sufficient transmission and generation reserve capacity, establish liquid wholesale markets and opportunities for cross-border cooperation in relation to the security of electricity supply, and more.

Directive 2009/28/EC obliges member states to open their power grids to energy from renewable sources, including via priority grid access (priority dispatch).

DIRECTIVE 2012/27/EU on energy efficiency and DIRECTIVE 2010/31/EU on the energy performance of buildings aim to improve energy efficiency in the EU. The Georgian government is working on a new energy law and Georgia’s parliament is expected to table the law by the end of 2019.

DIRECTIVE 2008/92/EC seeks to improve the transparency of gas and electricity prices and the terms of sale to industrial end-users.

A memorandum for the interchange of information signed between GeoStat and GNERC in 2017 supports EU Regulation 1099/2008 regarding energy statistics. The energy balance of Georgia for 2013-2017 is now available on the GeoStat website.

Vertical Unbundling

Most importantly, the EU directives call for vertical unbundling. That requires the separation of the operation of electricity networks at the transmission level from production and supply functions. Vertical unbundling can take place in the following ways:

Ownership unbundling restricts operators of transmission grids to be affiliated or be a part of a business group that also supplies or generates electricity but a person or a company can still hold non-controlling minority shares of the later.

The ISO approach enables vertically integrated companies to retain ownership of their network assets, but the network is managed by an ISO. That ISO must be separate from the vertically integrated company. The ISO will need to comply with the same unbundling requirements as other network operators and cannot hold any interest in a supply or generation asset. Additional regulatory controls are needed to strengthen the ISO model.

The Independent Transmission Operator (ITO) or Transmission System Operator (TSO) model allows integrated supply and transmission companies, but those companies must comply with additional rules to ensure the two activities are operated independently. The ITO model will only be applicable in member states where TSOs are part of a vertically integrated structure. Member states that have already introduced the ISO model or mandatory ownership unbundling models will not be able to revert to an ITO model. Thus, the ITO model constitutes the


lowest threshold for network unbundling.

Obstacles to Meeting the EU Energy Directives

The electricity market law is not yet adopted and its technical implementation may take more than one year. Major risks to the reform includes contractual obligation of the government with the power distribution companies, readiness of all potential market participants (especially small HPPs), and non-existent power supplier infrastructure.

Real unbundling may not be achieved until 2025. Distribution companies currently supply and distribute electricity to consumers, meaning they do not comply with EU Directive 2009/72/EC. Also, the tariff-setting mechanism between the two large distribution companies and the government is valid until 2024.

High transmission costs offset the benefits of cost-efficient HPPs. Small-capacity HPPs are eligible to sell electricity to retail consumers, but enrollment is low because those producers are deregulated and can sell electricity to the wholesale market at prices higher than regulated HPPs. This is caused by increased volumes of imports and increased supply of electricity from newly built HPPs with ESCO’s PPAs (both imported electricity and PPA prices are higher than those from any other source of electricity).

High share of socially vulnerable households creates additional costs on the system. The PSO directive requires electricity access to be provided to vulnerable households. Although “vulnerable” is not clearly defined, according to Georgia’s Social Service Agency, the country had 129,76612 vulnerable households as of the end of 2018, or 12.2% of all households. The government can allocate funds to cover gaps for the most vulnerable part of the population. This can be done through a system of vouchers or donations.

Priority grid access to renewable sources will be difficult to implement until 2027. HPPs commissioned in Georgia after 2009 have Memorandum of Understanding with the government, PPA with ESCO, and a power transmission agreement with the GSE for the next ten years. Abolishing such agreements after 2018 gives disadvantage to the newly HPPs or other renewable sources.

Implemented Steps

In 2017 and 2018, Georgia has initiated new regulations concerning electricity market, including the following rules:

• Consumers that are connected to transmission lines of 35 kW capacity or more are treated as eligible consumers starting in May 2018;

• Power plants with installed capacity of less than 40 MW are deregulated since 2018;

• From September to May, wholesale electricity prices paid on electricity purchase from small capacity power plants by ESCO will be equivalent to upper limits of prices set to HPPs by the regulator;

• Distribution companies are given certain grace periods and conditions to create digital maps of distribution grid and integrate Supervisory Control and Data Acquisition (SCADA) elements in their accounting process;

• Tariffs for regulated generation, dispatch, transmission, and distribution companies will be based on three-year

12 Social Service Agency of Georgia


development plans created by the companies and an increased WACC of 16.4% (13.5% previously). The increase in WACC was mainly driven by the depreciation of the GEL against the USD.

In addition to those changes, the government has initiated a law on the energy sector that seeks to establish a legal framework for the generation, supply, dispatch, distribution, and trade of electricity. The new law proposes the following:

• Ensure supplier switching and a supplier of last resort (nominated by the government);

• Ownership unbundling (supply and distribution);

• Goals of increased energy efficiency and decreased CO2 emissions based on Georgia’s environmental, economic, and social security policy;

• Integration of smart technologies into the electricity market;

• Promotion of renewable energy;

• Support cross-border electricity trade to increase competition and diversification;

• Deregulate electricity prices;

• Implement measures related to the security and reliability of electricity supply;

• Protection of consumer rights and increased affordability of electricity;

• Public service obligation for distribution companies;

• Abolish cross subsidies among vertically integrated companies.

The proposed changes on deregulation, unbundling, and supplier switching will support the establishment of market-based electricity supply prices. However, prices for electricity generated by some plants will be set by the GNERC. The new energy model sets the scope for the electricity trading mechanism. It allows the government to launch a bilateral electricity market, a day-ahead market, a day-in market, and a market for balancing and ancillary services (TSO).

ELECTRICITY TRADING MECHANISMS (ETMs) AND THE MARKET MODEL

By signing the EU Association Agreement and by joining the European Energy Community, Georgia has committed to bring its regulations in line with EU directives. Currently, ESCO is trading the balancing electricity (including import). This model of the market is not harmonized with EU practices of free electricity market. New ETM should replace the existing model by the free power market.

There has been no final consensus reached about the model of the new electricity market, however, there is an agreement among industry stakeholders, that in order to avoid unfair competition, new ETMs should establish trade formulae for the market participants that will consider certain caveats and limitations of the Georgian electricity sector (contractual obligations with distribution companies and PPAs).


Proposed ETM by the new rules

The desired (and most discussed) market structure is a day-ahead market but participants are allowed to maintain direct contracts (over-the-counter market) and are encouraged to utilize bilateral trading. Our ETM market model would introduce the following market participants and trading mechanisms:

• Day-ahead market: Bids and offers for the next day are made every day until 12:00, on an hourly basis. Market participants participate directly or via traders.

• Market Operator (MO) operates the day-ahead market, matches bids and offers, and calculates the market clearing price. That could offset the price difference between PPAs and the market and restrict inefficient bidding by establishing a price floor at a weighted average price for all market bids. ESCO can be transformed into the MO.

• Generation companies, trading companies, and consumers participate in trades. To avoid price spikes during peak hours, prices can be capped based on the most expensive imported electricity.

• Aggregators offer a large customer pool to suppliers. A new category of market players will carry out balancing, forecasting, scheduling, and demand management. Aggregators will introduce efficiency into the market by allowing small producers not to waste resources (water for HPPs) and avoid influence by large consumers and DSOs.

• The transmission system operator (TSO) ensures the security of the power system in real-time. The TSO would balance supply and demand and register bilateral contracts. The TSO also could determine the market clearing price. Every market participant (consumer) pays a capacity charge to the TSO, which is set by the GNERC. The TSO would be able to introduce congestion management tools/tariffs to better balance the system; the revenue can be used for capex at the TSO to further support the security of supply.

• The central clearing party is an intermediary between the buyer and the seller. The clearing function can be implemented by financial institution that can take on risk and offer trading margins to market participants.

• GNERC ensures fair competition. The regulator would be responsible for registering traders that can enter into long- and short-term deals, as well as for ensuring fair competition.


TABLE 6: NEW ELECTRICITY MARKET MODEL

Source: TBC Capital

Until 2025, some privatized HPPs may have ability to sell electricity below marginal costs, while cost of capital was not fully included in the privatization price and was redistributed over ten years. To avoid price dumping, TSOs could charge the discounted capital cost as a fee to this category of HPPs and fund the difference between PPA prices and market prices for PPA holders. Also, privatized HPPs could be precluded from the modified ETM. However, this might significantly reduce the trading.

The market system would also be able to register long term direct contracts through trading platforms. Full deregulation of generation plants and unbundling (high voltage transmission, supply and distribution) are prerequisites. Under this model, high-voltage transmission and distribution activities are not deregulated.

Additionally, after the expiration of contractual liabilities with distribution companies, privatized HPPs and PPAs, the market will be free of the current imperfections and would be capable of setting up equitable and competitive environment.

Main stakeholders affected

The implementation of the ETM will create costs, but it will impact stakeholders positively. Although staff training and new technology brings additional costs, market participants will benefit from the free trade and improved service quality. The liberalization of the market should attract more investors and increase the security of electricity supply.


TABLE 7: COSTS AND BENEFITS OF MARKET PARTICIPANTS WITH THE NEW ETM

Source: TBC Capital

The new ETM could face risks related to technology (hacking and glitches) and price volatility as the share held by regulated producers would be reduced. Growth in electricity consumption will cause greater price volatility. Currently, all market prices are directly or indirectly controlled by GNERC and ESCO, who try to level costs and reduce price fluctuations. In addition, there is no peak hour price. After the proposed reform, HPPs with reservoirs and TPPs will try to capitalize on the opportunity presented by high prices during peak hours.

IMPACT OF REGULATION ON ELECTRICITY PRICES AND THE INVESTMENT ENVIRONMENT

The upcoming changes to Georgia’s electricity sector are expected to moderately increase the price of electricity, increase long-term investment, improve service quality, and benefit the environment.

Electricity price

Electricity prices in Georgia are determined through the deregulated and regulated markets. Deregulated power plants can benefit from free trade and high export prices, while regulated plants are controlled by the GNERC. The regulator creates downward pressure on electricity prices.

The additional market participants and services and the capital investments in platforms and metering infrastructure will increase the costs of producing and delivering electricity to consumers. Based on the experience of other countries and on our own cost estimates, we estimate the impact on electricity price at up to 10% within the next 2-3 years, with all costs absorbed by consumers. The estimate is based on additional capex and the additional participants and costs of services moving to the new trading system.

Overall, we expect the increasing demand for electricity and the lack of sufficient generation capacities will push prices up. The expected infrastructure investments will also contribute to the price growth. However, the average price increase should be moderate, and it is worth remembering that the market will retain a regulated part of

MARKET PARTICIPANTS COSTS BENEFITS

Generation companies13 Employee training Free trade

Deregulated HPPs Employee trainingParticipation in the free trade and reduced influence from the large consumers

Currently regulated generation companies

Employee training, risk of price fluctuations

Potential for high gains in times increased demand

Eligible consumers New metering system and trading technologies No change

Consumers Tariff increase up to 10%14 higher competition will increase efficiency and will reduce prices in the long-run

DSOs New metering system and trading technologies Decreased employee costs

13 Excluding Enguri and Vardnili HPPs, privatized HPPs, HPPs with PPAs and TPPs14 TBC Capital’s estimates based on data from EU countries, that implemented similar electricity market reforms


the market alongside the deregulated part.

Investment in the sector

In this cycle of lower energy prices, the abolishment of the PPAs is likely to reduce the growth in investment into the sector in the short-run. That reduction will hit medium and large HPPs, whose capital costs of investment are higher than those of small HPPs. Other sources of renewable energy will also struggle to attract investors.

The energy sector has a long business cycle and it takes several years for reforms to influence investment and consumption patterns. In the long-run, investors will show greater interest in the market as the new ETMs shows its effectiveness and resilience. Clear and transparent market rules will create the preconditions to attract more investment into the sector.

Service quality and environment

The environmental impact of the reform will primarily depend on the reform’s outcomes. An increase in investment will create greater pressures on the environment, while increasing renewable capacity will have a positive effect. An accurate environmental impact assessment can help minimize potential environmental issues.

The EU Water Framework Directive requires the implementation of incentive-based economic instruments for water resource use. Other EU directives also place a greater emphasis on sustainable resource use, the promotion of biodiversity, decreasing pollution, and increasing energy efficiency. The implementation of EU regulations will help deter negative environmental consequences. Overall, we expect that the reforms will have only a moderate or low impact on the environment.

Security of electricity supply

In most goods and services markets, when demand grows and supply reaches capacity constraints, prices rise to ration demand. In electricity markets, relatively minimal demand can be rationed through short-term price movements. This is replaced by rolling blackouts. This reflects both the limited use of real-time pricing and the system operator’s need to adjust demand quickly in specific locations.

The available demand response instruments are poorly integrated with spot markets and are likely inefficient at depressing prices. Moreover, the prices paid for demand response or the prices that can be avoided by responding to price signals are too low relative to the cost of carrying generating capacity reserves to meet planning reserve margins in some cases.

We believe that improving demand response should be given higher priority in wholesale market design. Therefore, it is very important to maintain a steady pace of investment in the sector after the reforms are completed. This is one of the most significant factors and indicators of healthy reforms and the future development of the electricity industry in Georgia.

Electricity market reform in EU countries

Electricity prices vary in different countries because of the energy supply mix, the transmission network, trading mechanisms, trading rules in neighboring countries and regulations. Initially, the European Commission singled


out price differential as the most important rationale for liberalization. That, however, did not have the expected effect. In almost all countries that have fully liberalized the household market, electricity prices for household customers have increased steadily.

The Czech Republic and Croatia completed electricity market reforms in 2009 and 2011, respectively. Electricity prices grew 7-10% in the two countries in the initial years before later decreasing moderately.

FIGURE 14: ELECTRICITY PRICES IN THE CZECH REPUBLIC AND CROATIA (EUR cent PER KWH)

Source: Eurostat

Prices for wholesale consumers are lower than retail prices. Costs related to billing, customer service, bad debt, advertising, and promotion add up quickly and reduce profit margins. Lower prices for wholesale consumers could be explained by the fact that industry consumes a huge amount of energy on a daily basis, rather than being low because of the impact of the new legislation.

Supplier switching is an important benefit of the deregulation of the electricity market. In most countries, large industrial customers are more likely to switch and to do so more quickly than smaller industrial and commercial customers. Residential customers switch more slowly and are more likely to remain with the incumbent distribution company, especially when the incumbent must offer a regulated default price that is at or below the wholesale market price. The Georgian market carries the same risk as long as the current third-party access rules remain in place (we believe these rules are unlikely to change until the contracts with Telasi and EPG expire). Additionally, the default service price may have to be significantly higher than the comparable wholesale market price to induce substantial amounts of customer switching.

Based on the example of EU countries, electricity sector reforms can have significant benefits but can also carry significant costs if the reforms are implemented incompletely or incorrectly. We believe that when electricity restructuring and competition programs are designed and implemented well, electricity sector operating costs, physical network losses, generator availability, quality and availability of service, investment, price levels and structures, and other performance variables improve by more than the typical state-owned or private regulated vertically integrated monopoly.


Overall, membership in the European Energy Community and adopting the EU directives will enable Georgia to promote the development of renewable energy and energy efficiency, boost investment, and increase competition in the electricity market. However, even with increased competition, electricity prices are expected to increase with the increasing demand and the lack of generation capacities, and because of the costs of the new regulations.

GLOBAL ELECTRICITY MARKET TRENDS ENERGY SOURCES GLOBALLY: SOLAR AND WIND POWER ARE ON THE RISE

Tackling climate change and air pollution is one of the most important challenges worldwide. However, growing demand for electricity is often met with non-renewable sources. According to the International Energy Agency (IEA), global electricity generation grew at a 2.8% 6-year CAGR to 26,700 TWh in 2018. The IEA sees generation increasing at a 1.9% CAGR over the next 12 years to 33,500 TWh as of 2030.

Electricity generation from solar photovoltaic systems (Solar PVs) and WPPs has grown fastest, increasing at a 32% and 17% 6-year CAGR to 534 TWh and 1,335 TWh in 2018, respectively. Due to the expansion of clean energy sources, the share of fossil fuels in electricity generation decreased to 65% in 2018 from 68.0% in 2012. However, their share is still high and there is substantial room for renewables. IEA projects that the share of fossil fuels will decrease to 54% by 2030, with solar and wind stealing market share.

The earthquake and tsunami in Japan forced several nuclear plants to shut down in 2011. As a result, the production of electricity from nuclear power fell to 2,460 TWh in 2012 from 2,756 TWh in 2010. Since 2012, nuclear power production has grown at a 1.4% 6-year CAGR to 2,670 TWh in 2018. Nuclear advocates insist the technology is important and have zero emissions, but damages associated with the later could be huge.

FIGURE 15: SHARE OF ELECTRICITY GENERATION (TWH) WORLDWIDE BY TECHNOLOGY IN 2012-2017 AND PROJECTIONS TO 2030

Source: IEA


GREEN ECONOMY: A TECHNOLOGY-BASED INDUSTRY

Developed countries are trying to promote renewable energy, increase energy efficiency, and embrace electrification. Green economic models support the concept of smart cities, which include smart elements in transportation, energy systems, and other areas across the economy.

The World Economic Forum (WEF) offers three main trends that will shape the future of electricity: electrification (decreasing carbon emissions through clean energy use), decentralization (promotion of energy efficiency and self-generation of electricity with micro power plants), and digitalization (new appliances and automation systems to optimize electricity consumption).

TABLE 8: THREE CORE TRENDS OF GRID EDGE TRANSFORMATION

Source: WEF, TBC Capital

Electrification increases demand on electricity through introducing energy intensive technology. EVs are one of the main components of electrification. We expect that EVs in Georgia will represent more than 20% of total market by 2030 and increase in demand on electricity will range from 6.0% to 8.0% of expected consumption by that date.

Decentralization and energy efficiency are supposed to slow down the increasing demand on electricity. According to 2014 Census, more than 90% of dwellings in Georgia are built before 2010 and last majority of these building don’t meet modern energy efficient criteria’s. Government is considering implementation of new energy efficiency law on buildings and set power saving requirements for construction and renovation works. Also, energy efficient works in building includes switching to more cost-effective household appliances. We estimate that switching to more efficient bulbs can decrease demand on electricity by 0.7 TWh, around 3% of total demand in 2030.


Digitalization includes technologies used to shape electricity supply processes in smart cities. Smart Grids15

progressive technology supports the safe transmission of electricity and provides the information needed for the efficient functioning and monitoring of the system and could be relevant to integrate in Georgia’s power sector. Smart grids also help reduce electricity losses and include the following technologies:

• Advanced metering infrastructure: Smart electric meters allow households to control electricity consumption and increase efficiency by increasing the profile of energy-intensive appliances and abnormal consumption patterns.

• Advanced electricity pricing: Electricity pricing software allows real-time pricing that is based on production costs. Electricity produced from variable renewable energy is unstable and hard to project, so more costly energy sources are used to balance shortfalls. Cost-oriented pricing reduces demand peaks and promotes energy efficiency. With the development of mobile apps, households can adjust electricity demand to the variable prices.

• Demand response: Demand response supports the stability of the electricity system by shutting down certain large consumers during peak hours or periods of generation shortfalls. Pre-agreed consumers receive notice before being shut down. In return, they receive a discount on their electricity bill based on the intensity of the shutdowns. During periods of electricity oversupply, pre-agreed consumers increase their demand. The demand response can be a more cost-effective way to control peak loads than it is to add more generation capacity.

• Distribution automation: A special device monitors voltages and equipment to prevent power outages and enables feeder automatic switching. Remote fault indicators and smart relays detect abnormal voltage levels and protect feeders, while smart inverters help regulate voltage and frequency in the grid.

• Microgrids: Small electricity grids supply electricity to customers that are disconnected from the main grid. Since long-distance transmission is costly (infrastructure costs) and carries high electricity losses, microgrids are valuable for small villages and islands with their own energy sources that are separate from the main grid.

• Renewable resource forecasting: Advanced computer models estimate electricity generation by wind and solar sources. The generation projections help the system operator manage supply peaks and valleys.

Electrification and digitalization expands the consumer base and creates upside for electricity demand. In response to the increasing demand, it is important to integrate variable renewable energy into the network. Electricity storage systems support variable renewable energy by conserving energy during periods of oversupply, to meet demand peaks. At the same time, electricity storage systems increase flexibility for EVs, solar home systems, and other electric appliances that need stable electricity supplies.

Currently, pumped hydro storage accounts for 96%16 of all electric storage systems globally; however, the cost of lithium-ion batteries is decreasing and stimulating the use of battery storage systems. The price/kWh of a lithium-ion battery decreased at a 20% 8-year CAGR to USD 176 in 2018 and is expected to decrease further to USD 73 by 2030.

15 Smart Grids and Renewables: IRENA (2015)16 Electricity Storage and Renewables IRENA (2017)


FIGURE 16: PRICE OF LITHIUM-ION BATTERY (USD) PER KWH OF ELECTRICITY WORLDWIDE

Source: Bloomberg New Energy Finance

Solar technologies are getting cheaper as the cost of lithium-ion batteries decreases. The global cost of electricity generated by solar PVs decreased at a 17% 7-year CAGR to USD 0.09/kWh in 2018. The cost of wind energy has dropped to USD 0.06/kWh. However, WPPs are less relevant for households as they require more land and more substantial investment, and they have some constraints in grid integration.

HPPs remain the least costly source of energy, with an average global cost of USD 0.05/kWh in 2018. However, the cost of hydroelectricity has been increasing 2% annually. In addition, tensions over the negative side-effects of building HPPs on the ecosystem are on the rise.

In Georgia, the price of household electricity price was USD 0.09/kWh17 in 2018, close to the cost of electricity from solar PVs and higher than the cost of wind and hydro power. However, because solar PVs can be integrated by households without intermediary costs (transmission and distribution) and given the decrease in solar equipment costs, demand for solar PVs could soon increase sharply in Georgia. Additionally, self-consumption of solar energy solves the intermittent problem of integrating renewable energy into the grid.

17 Annual consumption exceeding 3,600 kWh


FIGURE 17: COST OF ELECTRICITY (USD) PER KWH BY TECHNOLOGY WORLDWIDE

Source: IRENA

Electricity consumption globally is expected to increase alongside digitalization and electrification. At the same time, decentralization and energy efficiency efforts reduce demand. Green economics and the concept of smart cities support the reduction of CO2 emissions by decreasing demand for fossil fuels, which still account for 65% of global electricity production. However, renewable energy is becoming more economically viable as technology develops, and the share of electricity generated from renewable sources is expected to increase.

RENEWABLES IN GEORGIAHYDRO, WIND AND SOLAR: BROADLY UNTAPPED POTENTIAL

Georgia is ranked 40th globally by per-capita freshwater resources. Only four EU countries and one CIS country (Russia) are in the top 40. Moreover, Georgia has successfully utilized its hydro potential and is now ranked 29th in renewables as a share of total installed capacity (78%). Renewable sources accounted for 83% of all electricity produced in Georgia in 2018.


FIGURE 18: RANKING OF DEVELOPED MARKETS AND NEIGHBORING COUNTRIES IN FRESH WATER RESOURCES (‘000 M3) PER CAPITA (2014) AND RENEWABLES AS % OF TOTAL INSTALLED CAPACITY (2015, GEORGIA: 2018)

Source: World Bank

The Paris Agreement aims to keep the growth in global temperatures well below 2C in the 21st century, and aims to do so by promoting investment in clean energy and decreasing greenhouse gas (GHG) emissions. In response to global warming, the EU has set new 40/27/30 targets (a 40% decrease in CO2 emissions and at least 27% share of renewables in energy consumption by 2030). In 2018, renewables (hydro, biomass, wind, and solar) accounted for 38%18 of all electricity produced in the EU.

Georgia submitted its climate action plan to the United Nations Framework Convention on Climate Change (UNFCCC) in September 2015 and officially joined the Paris Agreement in 2017. The country plans to reduce its GHG emissions by 20% compared to its Business As Usual scenario (BAU), which is projected at 3819 MT of CO2 by 2030. The government should promote policies to decrease the costs of investing in clean energy, which will support the country’s path towards its target.

In 2015, Georgia introduced a new energy law that supports renewables. According to the law, electricity power plants owned by retail consumers (installed capacity of less than 100 kW) are treated as micro electricity power plants. The GNERC reports that 67 solar PVs were registered as of year-end 2018, with a total installed capacity of 0.7 MW. The advantages of the micro power plants include:

• No authorization required from market regulators;

• Self-consumption is exempt from taxes;

• Electricity generated above the self-consumption level can be supplied to the grid and then re-supplied upon request for self-consumption;

18 Quarterly Report on European Electricity Markets: European Commission (2018) 19 Georgia’s Intended Nationally Determined Contribution: UNFCC (2015)


• Owners of micro power plants can sell electricity to distribution companies at the weighted average price for purchased electricity.

Considering decreasing solar energy costs, investment in micro electricity plants can become an opportunity for households in Georgia. The expected growth in electricity prices, which reduces capital costs and decreases payback periods, could further stimulate that process.

Georgia also uses solar and wind energy. The country has one WPP located in the Kartli region, with installed capacity of 20.7 MW and annual generation of nearly 0.1 TWh. According to the GSE’s plan for 2019-2029, the TSO will be able to integrate 333 MW of wind and 130 MW of solar energy into the grid by 2021. The TSO plans to double those capacities by 2025 and further increase the threshold to 1,332 MW for wind and 520 MW for solar by 2030.

Thanks to its abundant hydro resources and high share of renewables, Georgia has advantages over neighboring countries in terms of creating an economy focused on clean energy. Besides building new HPPs, the country can meet increasing demand for electricity by realizing its currently untapped wind and solar potential. Policy actions from the government can help stimulate that process.

GREEN BONDS AND RENEWABLE FINANCING: AN OPPORTUNITY FOR THE PRIVATE AND PUBLIC SECTORS

Cooperation by the public and private sectors in developing financing instruments for renewables could spur private investment into the sector. Green banks20, as far as National Development Banks are working with private lenders worldwide to finance environmentally beneficial projects. Green banks invested USD 430mln in energy efficient projects in 2017, including more than USD 350mln in the construction sector.

Examples of successful cooperation between the private sector and international financial institutions (IFIs) in Georgia include: cooperation between TBC Bank and the EBRD to provide subsidized loans to households to retrofit homes with energy efficient technologies, as well as the long-term line of credit from the Green for Growth Fund to Basisbank to support small business energy efficient projects.

Household adoption of cost-saving technologies supports the energy sector. However, the impact will be minimal without the involvement of large institutional investors. Green bonds, which raise capital for new and existing projects that have environmental benefits, are a new trend in energy sector finance. The market for green bonds is growing rapidly, with total issuance growing at a 38% 2-year CAGR to USD 167bn21 in 2018. Sustainable Banking Network (SBN) projects that issuance of green bonds is expected to exceed USD 250bn in 2019.

Proceeds from green bonds typically go to renewable energy initiatives, low emission construction, and energy efficiency projects; those three categories accounted for 64% of green bond proceeds as of 1H 2018. The breakdown by issuance category has been broadly unchanged over 2016-2018.

20 Green Investment Banks: Organization for Economic Co-operation and Development (2017)21 Creating Green Bond Markets: Sustainable Banking Network (2018)


Potential benefits for investors Potential benefits for issuers

Comparable financial returns with the addition of environmental benefits Additional source of green financing

Satisfy ESG requirements for sustainable investment mandates

Improve investor diversification and attract buy-and-hold investors

Direct investment in the “greening” of brown sectors and social impact activities Enhance issuer reputation

Increased transparency and accountability on the use and management of proceeds

Strong investor demand and oversubscription benefits

FIGURE 19: SHARE OF GREEN BOND ISSUANCES (USD) BY CATEGORY AS OF 1H 2018

Source: SBN, TBC Capital

According to the SBN, the market for green bonds has been led by public sector issuers, including municipalities, state-backed entities, government agencies, and national and international development banks. At the same time, financial corporates issued USD 49 bn in 2018, 29% of the total, up from 14% in 2017.

TABLE 9: BENEFITS FOR INVESTORS AND ISSUERS OF GREEN BONDS

Source: IFC, TBC Capital Research

The National Bank of Georgia (NBG) became a member of the SBN in September 2017. The regulator plans to develop Environmental, Social, and Governance (ESG) criteria for financial market participants to support sustainable financing. The NBG and TBC Capital have translated the “Green, Social and Sustainable Bond Principles”, which was developed by the International Capital Market Association (ICMA), into the Georgian language.

The development of a framework for green bonds is an opportunity to increase financing from IFIs across different sectors in Georgia, including the power sector. Raising capital through green bonds will help realize projects with environmental benefits and support the government’s policy objectives.


POWER SECTOR RISKS: UPSIDE FROM A FIXED PRICE AND ABOLISHMENT OF PPAsOverdue of energy policy may delay investment in the electricity sector: Delays in deregulation, subsidized tariffs, and problems with construction permits (including public pushback) create downside for returns and increases project payback periods. The abolishment of PPAs, which were designed to hedge price risk, increases investment risk for generation companies. On the other hand, growing imports and the expected electricity deficit is expected to lead to the higher electricity prices in the coming years.

Risks of electricity supply interruptions are moderate. Domestic producers cover more than 90% of Georgia’s annual electricity consumption. However, Enguri HPP’s high market share (33%) decreases supplier diversification. The plant is not expected to be decommissioned, but ongoing repair works and problems with the Abkhazeti breakaway region are creating issues in generation and in the security of supply. Thanks to the increasing generation capacities, share of Enguri HPP is expected to decrease to 26% of total generation by 2023. Also, increasing transit volumes of natural gas via the new Shah Deniz pipeline creates a security buffer in terms of the electricity generated by TPPs.

Electricity market players are exposed to FX risks. Regulated prices on electricity in the local market in the medium term period, together with the depreciation of GEL against USD for the last year’s decreases sector revenue in USD. Also, depreciation of TRY against USD decreases export price of electricity in Turkey, the key export market.

Existing transmission grid is vulnerable when integrating variable energy. Intermittent problem of integration the wind and solar energy into the grid creates upper bound on additional capacities from adopting new technology. However, investment in infrastructure from GSE is expected to increase the threshold to 330 MW for wind and 130 MW for solar by 2021.

Additional capacities are pushing up prices and increasing tensions in the country. It is expected that electricity consumed in Georgia will have higher price than average price of generation today. Since regulated prices currently include only portion of the capital costs and they are “indirectly” subsidized from the government. In the future, decreasing the regulated part of the market could increase incentives for the investment in the electricity sector of Georgia. Although, part of the population is more vulnerable to electricity price increase and government could subsidize socially unsecured population.


ANNEXFORMING A FULLY COMPETITIVE MARKET:

Over the last decade Georgia’s electricity sector has undergone significant reforms. It has been transformed from a dysfunctional vertically integrated system into a well-functioning, largely liberal market structure.

TABLE 10: ELECTRICITY MARKET DEVELOPMENT STAGES

Source: GNERC

TSOs are the owners of the electricity transmission grid. Besides carrying transmission services in Georgia, TSOs also supports electricity cross-border trade. State owned GSE, Energotrans (subsidiary of GSE) and Sakrusenergo (50% owned by the MOESD) are the only TSOs in Georgia. GSE is the largest TSO, which owns and operates 3,350 km transmission lines and 90 substations countrywide22. Transmission network is managed by the National Dispatch Center and its technical maintenance is provided by three regional networks (East, West and Kakheti). GSE also manages the cross-border transmission lines interconnecting with the neighboring countries: Russia, Turkey, Armenia and Azerbaijan.

ESCO is trading with the balancing electricity through the direct contracts, grants licenses to entities for the wholesale trading and organizes trade with guaranteed capacities. Generation companies and importers sell electricity in the wholesale market to the DSOs, eligible consumers23, exporters, dispatch entities (for transit purposes) and generation companies (for self-consumption).

Market regulator GNERC is an independent state institution, financed by the regulation fees paid by licensees, importers, suppliers and the ESCO. The GNERC establishes fixed electricity purchase prices to HPPs with water

22 GSE23 Eligible consumers include: generation licensees, distribution licensees, large corporations and dispatch licensees


pump stations (regulator power plants). For partially regulated power plants and TPPs the GNERC establishes upper price cap on sold electricity. It should be noted, that electricity power plants built after 1 August 2008 or power plants with installed capacity of less than 40 MW are deregulated and can sell electricity with market based price. Export of electricity is deregulated, whereas price for imported electricity depends on importers’ terms. DSOs supply electricity to household and non-household users, with the price markup set by the GNERC.

Policy Maker the MOESD explores possibilities for improvements in infrastructure and harmonizes legislation to promote investment in the sector. The Ministry of Energy officially merged with the MOESD and continues operating under the Energy Policy Department and the Department of the Energy Reforms and Projects.

TABLE 11: ELECTRICITY MARKET STRUCTURE IN GEORGIA

Source: ESCO


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