Black Sea Regional Transmission Project

Project Design

GSE

September 2008

1 Project Objectives

Georgia’s power generation potential comes from both renewable sources of energy including hydro and wind power and from thermal generating capacity. Its hydro-power potential is estimated at up to 80 billion kWh p.a., of which up to 60 billion kWh may be economically attractive. The current system consists of about 60 hydro power stations with a maximal output capability of 8–9.5 billion kWh p.a. (i.e. 15% of the economically feasible potential) plus about 650 MW of thermal capacity at Gardabani, south-east of Tbilisi. In addition the construction of two units (150-160 MW) of Combined Cycle Gas Turbine power plants is envisaged. Thermal generation is mostly used in winter to balance low water availability, but it would also be available for export in off-peak demand season (spring-summer).

There is a significant generation-load imbalance in the Georgian power system: two-thirds of Georgia’s energy resource is located in the Northwest, while two thirds of the domestic demand is located in eastern Georgia, and most of the potential export market is located in countries south of Georgia (e.g. Turkey, Iran and Iraq, all of which experience rapid economic development and growth in electricity demand). Power delivery to these markets requires a reliable high voltage transmission network. At present only one strong line connects West and East Georgia, the 500 kV transmission line “Imereti” – “Kartli-II” – “Kartli-I”. Hence, in case of any fault on this line, especially during autumn / winter, a large power deficit is incurred in the East, including frequent total system blackouts. Apart from reducing domestic grid reliability, this also limits existing and future power swap or export potential. In addition to being an exporter of electricity, Georgia wishes to seize an opportunity for acting as a transit country, notably for electricity exports from Azerbaijan to Turkey.

The project under consideration serves 3 main purposes:

Strengthening the 500kV Main System in GeorgiaProvide infrastructure for export of surplus hydro generated energy in GeorgiaProvide infrastructure for a Georgian hub for power trading in the Caucuses region

Specifically the project will extend the Georgian main 500kV system with addition of 2 new 500kV links from Gardabani and Zestaponi to a new 500kV substation near the Turkish border at Akhalsikhe. Akhalsikhe will be connected to the Turkish EHV grid at Borchka asynchronously using a Back-to-Back HVDC link at Akhalsikhe and a 400kV overhead line. The line construction will be divided between the Georgian side (~20km) and the Turkish side (~130km). The Turkish investment is estimated to be €45 million.

The project idea is the subject of a number of studies on the Georgian/Regional Transmission Systems:

‘Feasibility Study for the Georgia High Voltage Transmission Lines Project’ by Kuljian Corporation (funded by USTDA)‘Regional Power Transmission Extension Plan for Caucasus Countries’ by Fichtner (funded by KfW)‘Potential export markets for Georgia electricity’ by ECON (commissioned by Ministry of Energy of Georgia)‘Power Transit Capability Analysis from Azerbaijan to Turkey’ by Georgian Centre for Transmission System Planning1 sponsored by USAID/USEA‘Electric power transit to Turkey from Russia/Armenia’ by GSE system group

The Kuljian Fichtner and ECON studies are reviewed in Annex 1, while the GSE/GTU work is considered in Annex 6 – Load Flows and Dynamic Studies.

1 Cooperation between Georgian State Electrosystem (GSE) and Georgian Technical University (GTU)

A companion project to facilitate the transit element is the completion of a new 500kV connection between Georgia and Azerbaijan. The line length for this connection is estimated at 230km – 3okm on the Georgian side and 200km on the Azeri side. The investment costs are estimated as €12 million for Georgia and €80 million for Azerbaijan.

2 Project Scope

The project requires the building and commissioning of:

New 500/400/220kV substation at Akhalsikhe near the Georgian/Turkish Border.New 1000MW Back-to-Back HVDC Unit 500/400kV at Akhalsikhe.New 400kV overhead transmission line from Akhalsikhe to the Turkish border – 20km of single circuit line. (It is expected that Turkish counterparts will complete the line from the border to Borchka 400kV Substation in Turkey).Completion of 500kV overhead transmission line from existing Gardabani 500kV substation to Akhalsikhe – 190km of single circuit line with 15km double circuit entry to Akhalsikhe. Approximately 68km of this connection was built in the late 1980’s but needs restoration/rehabilitation. The remaining 137km will be new construction. Completion of 500kV overhead transmission line between existing Zestaponi 500kV substation to Akhalsikhe – 56km of single circuit line with 15km double circuit entry to Akhalsikhe. Approximately 17km of this connection was built in the late 1980’s but needs restoration/rehabilitation. The remaining 54km will be new construction.Extension of Gardabani 500kV substation with a 500kV cubicle to connect the Gardabani – Akhalsikhe line.Extension (and re-organisation from ring to breaker and half busbar scheme) of Zestaponi 500kV substation to connect the Zestaponi – Akhalsikhe line.Extension of GSE’s SCADA system to accommodate the new infrastructure.

3 Benefits

The project will benefit both Georgia and the local region by increasing the reliability of the Georgian EHV backbone network and by providing trading possibilities between the nations of the South Caucasus. Georgia, Armenia, Azerbaijan, Russia and Turkey will have the possibility to cooperate in the export, import and transit of electrical energy. All these systems can also benefit from increased reliability and reduced spinning reserve. Both Georgia and Turkey will increase their use of Hydro generation thus reducing the use of fossil fuel energy and decreased carbon emissions.

3.1 Financial

In addition to benefits to the project company, other entities in Georgia benefit; GSE will benefit from the additional energy through its network and increased reliability of the main system reducing undelivered energy and hydro generators and other Independent Power Producers (IPPs) will be provided with the necessary infrastructure to export excess energy to Turkey.

3.2 Georgian Network Reliability

The addition of the second route to the 500kV main system from Zestaponi to Gardabani will increase the reliability of the power supply from west to east in Georgia. Undelivered energy due to 500kV faults (and indeed some 220kV outages) will be reduced.

In 2007 the undelivered energy due to faults on the 500kV system (excluding the Imereti Line) was 1.2 GWh. At an outage cost per kWh suggested by Fichtner (EUR 0.4) this represents a loss to Georgia of EUR 480,000 per annum which will be avoided by the new project.

Moreover, the number of permanent faults on the 500kV system that impact on customer supply will be reduced. The following tables illustrate this (based on an internationally accepted rate of 0.4 permanent faults per 100 km years):

Line name Length(km)

Fault Rate(per 100km-year)

Expected Faults/Annum

Imereti 130 0.4 0.52Kartli I/II 340 0.4 1.36Total Equivalent before new Project

490 0.4 1.88

Table 3-1: Existing 500/330kV System Faults Rates

Line name Length(km)

Fault Rate(per 100km-year)

Expected Faults/Annum

Imereti 130 0.4 0.52Kartli I/II 340 0.4 1.36Akhalsikhe - Gardabani 205 0.4 0.82Akhalsikhe - Zestaponi 70 0.4 0.28Total Equivalent after new Project

130 0.4 0.52

Table 3-2: New 500/330kV System Fault Rates

Tables 3-1 and 3-2 show that the addition of the new internal 500kV connections (which parallel the Kartli 500kV Lines between Zestaponi and Gardabani) will reduce, on average, the 500kV faults which directly impact on customer supply from just under 2 faults each year to 1 fault every 2 years i.e. the Imereti line fault rate.

3.3 Reduced Spinning Reserve

Strengthening the connections between Georgia and Turkey will reduce the spinning reserve requirements for both systems. This will allow the system operators to share spinning reserve thus reducing the need to schedule expensive thermal generation on both sides.

3.4 Facilitating Future Hydro Development

Future development of medium/large hydro generation in Georgia will be dependent on the availability of markets for the energy. The hydro projects currently at the development stage (Oni, Namakhvani and Mtkvari cascades) will have the bulk of their energy available during the summer months, the period when Georgia already has excess capacity. Therefore they will need access to external markets to be viable for investors. This project will have capacity to provide access to the Turkish market for these new hydro generators; thus improving the investment climate in the Georgian power sector.

3.5 Reduction in System Losses

Annex 7 shows the effect on losses expected on the Georgian transmission system by the introduction of the 2 new connections to Akhalsikhe. The average percent reduction in losses is 0.26%. Assuming a national load of 9 TWh and average generation cost of €0.025 / kWh, the avoided cost of generation is € 585,000 per annum.

3.6 Reduction in Carbon Emissions

Thermal generation can be reduced or replaced by hydro by:

The reduction in system lossesImprovement of connectivity between West Georgia (where the main hydro generation is located) and the load centre at Tbilisi where there is mostly thermal generatorsExport of surplus hydro from Georgia to Turkey where load growth is more than 5% per annum and the system’s specific CO2-emissions are higher than in Georgia. Assuming that the line will be utilised for export of hydro generated electricity for 6 months out of the year, this could mean a reduction in CO2 emissions of 1.1 m tonnes per year.

In addition the creation of a market for new hydro generated electric power will encourage the development of non-fossil fuel energy in the Region.

4 Cost Estimate

(€M)Akhalsikhe 500/400/220kV Substation including HVDC

500kV Station 10.5Back-to-Back HVDC 74.5400kV Station 5.0Sub Total 90.0

Substation Extensions Gardabani 500kV 1.8Zestaponi 500kV 5.6Sub Total 7.4

Overhead Line Construction Gardabani – Akhalsikhe 500kV 64.2Zestaponi – Akhalsikhe 500kV 19.0Akhalsikhe – Turkish Border 400kV 4.8Sub Total 88.0

Cost Estimate without Contingency 185.4Contingency 27.6Consultant 7.0Total 220.0Table 4-1: Project Cost Estimate

The cost estimate is based on experience of similar projects and excludes VAT and all other taxes and duties.

5 Time Schedule

The estimated project schedule is shown in Annex 5 and can be summarised as follows:

Completion DateLoan Approval Project Assessment Report 09/08

Agreement on Financing 10/08Loan Approval 04/09Loan Effective 06/09

Environmental Impact Assessment

Prepare ToR 09/08

Appoint Consultant 10/09Deliver Report 04/09

Appoint Project Consultant Prepare ToR 09/08Appoint Consultant 10/08

Appoint Contractor(s) Issue Specifications and Tender Documents

01/09

Tenders Due 04/09Award Contract 06/09

Transmission Lines Route Survey 09/09Design and Tower Spotting 10/09Manufacture 04/10Foundation Works 09/10Installation and Stringing 03/11Commissioning 05/11

Substations Design 10/09Manufacture 03/11Delivery 08/11Erection 10/11Commissioning 02/12

Converter Station Design 12/09Manufacture 04/11Erection 03/12Commissioning 06/12HVDC Trial Period 09/12

Table 5-1: Proposed Time Schedule

The proposed schedule shows that the lines can be delivered in May 2011 and the substation works (excluding the converter station) in February 2012. This means that the new station at Akhalsikhe and the connections to Gardabani and Zestaponi can already contribute to the reliability of the main system in Georgia in early 2012, reducing losses and undelivered energy. The converter station will be available before the end of 2012 and therefore should be ready for the first new HPPs expected in late 2013, early 2014.

The loan approval and effectiveness date used in the schedule is taken to be the last of the 3 loans which is dependant on the completion of the environmental impact assessment (EIA). The effectiveness date is assumed to be 2 months following loan approval; to allow time for loan negotiation. This delay may also be reduced if the loan details are agreed earlier.

However, the critical path in this schedule is the EIA and the delivery of the converter station. Note that loan effectiveness is dependent on EIA completion and it is assumed that the main contract(s) will not be awarded until all loans are effective.

6 Turkish Market Analysis

A detailed analysis of the Turkish Power market and the potential for export from Georgian to Turkey is attached in Annex 2. The key conclusions of this analysis can be summarised as follows:The Turkish electricity sector has been deregulated. A large part of the generation assets are in private hands and there is a private wholesale market for electricity. Import and export of electricity to Turkey can be undertaken both by TETAS, the state owned wholesale trader, and 25 private companies that currently hold wholesale licences.Demand for electricity is growing rapidly and total electricity generation required in 2016 is expected to be 321-378 TWh, with an annual increase of 12-26 TWh or 6-7.5%. The load profile shows both a winter and a summer peak.Turkey is struggling to meet the surge in demand in the period to 2012 despite a massive expansion of hydro power generation, a scheduled ramp up of coal generation using domestic lignite and plans for the construction of nuclear power facilities. Increased load shedding is expected in Turkey in the period to 2012 unless the government is prepared to take draconic actions by raising end user tariffs for electricity significantly. The electricity prices in the private wholesale market in Turkey are among the highest in Europe. The private wholesale price increased by 13% from April 2007-April 2008 to an average of 7.7 Euro c/kWh.The main reason for the rapid increase in private wholesale prices is that the marginal producers in the system, gas fed generation facilities, face higher gas purchasing prices. The average gas import price in Turkey in 2008 is estimated to 223 Euro/tcm and is expected to increase in 2009. Wholesale prices are expected to remain high in Turkey in the medium term unless oil/gas prices fall significantly or a very substantial expansion of coal fired power generation using domestic lignite is sanctioned.Turkish policymakers are very interested in importing electricity from neighbouring countries including Georgia. Imports through a 400 kV line to Borchka in Turkey, even if it is fully utilised, would match only 2-4% of total electricity demand in Turkey and would not have a material impact on wholesale prices. As long as Turkey allows for imports, Georgian HPPs will be competitive in the Turkish market because of the very low marginal costs of operating HPPs. Turkish policymakers want private sector wholesale traders to import the electricity from Georgia and Azerbaijan and rules out TETAS providing any long term power purchase agreements at fixed prices to exporters of electricity.Credible private sector companies in Turkey are interested in acting as import agents for electricity from Georgia.Georgian hydropower projects will most likely be able to fully utilise the transmission line to Turkey for at least 6 months of the year in the period from April to September.

These conclusions show that there is a significant market in Turkey (in the short, medium and longer-term) for Georgian power and at attractive prices. There are some risks associated with selling to this market, notably:

Gas/Oil prices fall significantly – this is unlikely in the current world climateA move away from the deregulated environment to government control and sector subsidies – very unlikely due to Turkey’s EU aspirationsCheaper imports from SE Europe – it is unlikely that any EU based gas or coal generation could compete with Georgian hydro generationTurkish economic collapse – this would only delay the export opportunities but not eliminate them

7 Georgian Hydro Development

A detailed description of potential Georgian HPP development is attached in Annex 3. The key conclusions are summarised below:

Georgia has one of the largest untapped hydro resources in Europe. The technical/economic potential is estimated to up to 60 TWh of which approximately 8 TWh, or less than 15% of the potential, has been developed.

In 2007, hydro generation constituted approximately 78% of total electricity in the system, thermal generation 17% and imports approximately 5%, while about 8% of the generated electricity was exported, primarily in the summer months, when the generation capability is at its peak due to the seasonal patterns of the river flows in Georgia. Figure 7-1 below shows the existing annual generation pattern.

Figure 7-1: Generation profile and exports Georgia 2007

Hydro generation

Thermal generation

Import

Load curve

0

100

200

300

400

500

600

700

800

900

1 000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

GW

h pe

r mon

th

Georgia exported approximately 625 GWh of electricity in 2007, much of it on the basis of swap contracts with neighboring countries where excess summer generation was traded against winter generation. The net export totaled 192 GWh.

A comparison of the wholesale electricity price in Georgia and Turkey illustrates the difference in power purchase costs. While the average wholesale tariff for privately produced electricity in Turkey was 8.3.Euro c/kWh in the period August 2007 to July 2008 and 9.3 Euro c/kWh in July 2008, the average price in the same period in Georgia was 2.7 Euro c/kWh. Figure 7-2 below illustrates the differences over the year.

Figure 7-2: Wholesale prices electricity in Turkey and Georgia, March 2007–July 2008

Turkey private wholesale tariff

Georgia balancing tariff ESCO

0

1

2

3

4

5

6

7

8

9

10

Wh

ole

sa

le p

ric

e E

uro

c/k

Wh

Turkey 5,45 6,17 5,77 6,50 7,26 6,82 6,11 6,01 7,41 7,69 9,09 9,01 8,25 7,74 8,32 8,03 9,33

Georgia 2,38 2,52 1,72 1,74 0,89 1,74 2,85 3,64 3,72 4,04 3,75 3,85 2,90 1,19 1,53 1,53 1,15

March April May June July AugustSeptem

berOctobe

rNovem

berDecem

berJanuar

y Februa

ryMarch April May June July

The Georgian economy has been growing rapidly in recent years without a noticeable increase in the demand for generated electricity. In 2007, when the economy grew by 12.4%, demand for electricity generation increased by about 3%. Sluggish electricity demand was largely due to rapid energy efficiency improvements in the sector as the transmission and distribution losses have come down significantly. Figure 7-3 below shows the assumed demand forecast for Georgia 2008-16 (GWh).

Figure 7-3:

There are several large green field sites that the Georgian government has been promoting to private sector investors. These include the Namakhvani cascade, where a full feasibility study has been commissioned, and the Oni and Mtkvari cascades. The government is also reviewing the opportunity of developing the Upper Rioni river cascade between the Oni and Namakhvani cascade. The total annual generation from these sites is estimated at 5.7 TWh, almost doubling the total hydropower generation in Georgia.

All sites are expected to be developed with relatively small reservoirs, which, combined with the seasonal patterns of water flows, would imply that most of the generation takes place in the summer months when the prices in Georgia are at their lowest and when the country already is a net exporter of electricity.

The figure below shows the estimated annual generation profile of large HPP projects in Georgia.

Figure 7.4: Additional generation capacity and demand growth Georgia 2016

Assumed load growth 3 % p.a2007 (actual) 84382008 86912009 89522010 92202011 94972012 97822013 100752014 103782015 106892016 11010

The levelised unit costs for new HPPs in Georgia (shown in Figure 7-5 below compared with other technologies) indicate how competitive these new HPPs can be in the Turkish market: The hydropower plants in Georgia have levelised costs (including grid connection costs) that are half that of nuclear, coal and gas-based alternatives, given the high fuel prices prevailing in mid 2008. In the calculations we have assumed a hydro power facility life time of 30 years. Given the high oil/gas and coal prices prevailing in 2008, the HPPs are clearly the least cost generation option.

As oil/gas-based units will be the marginal producer in the Turkish/Georgian system, thus setting the price in the Turkish system after full deregulation of the wholesale market, they would determine the profit margin of the greenfield HPPs: The 20-year equity-related IRRs of the projects are estimated at 20-24%, which should make the sites very attractive for private investors.

0,0

200,0

400,0

600,0

800,0

1000,0

1200,0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Ge

ne

rati

on

GW

h p

er

mo

nth

Rehabilitation of existing HPPs

Upper Rioni Cascade

Mtkvari Cascade

Namakhvani Cascade

Oni Cascade

Load growth to 2016 3% p.a.

Thermal production 2007

Figure 7-5: Levelised Unit Costs for new Georgian HPP versus alternate technologies

0

10

20

30

40

50

60

70

80

90

Eu

ro/M

Wh

dis

co

un

ted

at

11

,4%

Investment O&M Fuel

Fuel 0,0 0,0 0,0 29,5 15,0 0,0 58,9 4,7 41,0

O&M 2,5 2,5 2,5 2,9 5,9 6,7 2,9 7,9 5,9

Investment 31,9 33,7 37,4 10,3 35,6 64,2 10,2 64,4 35,5

Namakhvani HPP*

Oni HPP*Mktvari HPP*

CCGT 200

USD/tcm

Coal 55 USD/t

Wind onshore

CCGT 400

USD/tcmNuclear

Coal 150 USD/t

Figure 7-6 outlines the approximate electricity available for exports from the four HPP sites in an average year, as well the carrying capacity of the line and the net capacity that would be available.

Figure 7-6: Energy available for export from new HPPs2016 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Oni Cascade 81,8 74,3 85,9 146,4 202,5 182,7 183,1 186,4 126,7 104,7 89,5 86,2Namakhvani Cascade 70,0 58,7 73,1 253,3 257,0 226,3 171,4 109,8 135,1 163,7 101,4 23,7Mtkvari Cascade 29,1 27,2 33,9 138,2 188,7 112,9 58,1 29,8 23,3 27,0 29,3 29,5Upper Rioni Cascade 85,2 71,4 88,9 308,3 312,8 275,3 208,5 133,7 164,4 199,2 123,4 28,8Rehabilitation of exisiting HPPs 120,5 127,8 128,6 122,6 149,6 141,0 184,3 179,4 123,7 83,6 108,4 106,1Export of electricity 2007 6,7 7,2 9,7 7,1 64,3 68,7 208,4 180,5 40,1 15,9 4,6 12,2Load growth to 2016 3% p.a. 240 216 229 205 172 160 172 176 166 176 212 259

Available capacity in the line 730 730 730 730 730 730 730 730 730 730 730 730Demand for capacity 2016 6,7 7,2 9,7 771 1003 847 842 644 448 15,9 4,6 12,2

Exportable power 6,7 7,2 9,7 730,0 730,0 730,0 730,0 644,1 447,5 15,9 4,6 12,2

It is realistic to assume that most, if not all of the large hydropower projects in Georgia will be (re-) financed through revenues from exports to Turkey provided that the Turkish wholesale buyers of electricity are prepared to pay 5.7–8.3 Euro c/kWh for Georgian electricity, with a start of delivery in 2013-14. If oil and gas prices remain above 80 USD/bbl in the medium run, it is realistic to assume that such contracts can be secured in Turkey at least at the lower end of the price range.

The construction of the transmission line to Turkey could help release up to Euro 1.3 billion of investment into large green field hydro sites in Georgia and also facilitate the development of a range of smaller sites. Because of the DSI taxation in Turkey on newly constructed hydropower plants, Georgian green field sites enjoy a significant cost advantage compared with comparable Turkish sites. The cost advantage for the Oni HPP compared with a similar site in Turkey could be as high as 20–30%, even when accounting for the cost of transmitting the electricity from Georgia to Turkey.

Without the transmission link with Turkey, there would be limited interest in the development of hydropower resources in Georgia unless domestic tariffs were to rise significantly or the prices in other neighboring countries like Russia, which already is connected to Georgia with a high voltage transmission line, would increase considerably.

Given the time it takes to develop the different hydropower projects in Georgia (3–5 years), it is likely that Georgia will only be able to provide significant amounts of electricity for export to Turkey in the period beyond 2013.

The prospect of having the access to a transmission outlet to Turkey will be crucial for the development of the hydropower potential in Georgia. A potential developer of one of the larger HPP sites in Georgia will most likely require a long-term guarantee of available transmission capacity to Turkey, preferably at a fixed price, before making investments in the development of the site.

8 Base Case Analysis

The base-scenario for assessing the financial and economic viability of the transmission project under consideration rests on two key assumptions:

The Turkish electricity market will be capable of absorbing up to 1,000 MW that can be channelled through the new transmission link with Georgia.The main source of electricity imported by Turkey will be hydropower sites developed in Georgia.

The first assumption takes account of the fact that recent projections prepared by TEIAS and EMRA suggest that by 2012 there will be a shortfall of electricity supply from existing, committed and planned generation facilities of the order of at least 25,000 GWh. This deficit will have to me met by new fast-track generation projects and imports. Given the expected imbalance between demand and supply, there is little doubt that the Turkish market could easily absorb additional supplies from or through Georgia, provided that such imports are cost-competitive. If the current prevailing wholesale electricity prices are taken as a benchmark, then Turkish import demand would be perfectly elastic at about 70 – 80 Euro/MWh for supplies even in excess of the transmission link’s maximum carrying capacity of 1,000 MW.

The second assumption is based on available evidence suggesting that Georgia’s hydroelectric resources are a lower-cost alternative to thermal generation plants fuelled with gas or coal (Annex 3, Table 3.6). Developing the hydropower resources appears to be a profitable undertaking, particularly if a large part of the energy could be sold in the Turkish market. Thus, establishing the transmission link with Turkey is a necessary condition for rendering investments in Georgia’s hydroelectric sites attractive. International tendering of the first sites is scheduled for October 2008, and the Georgian Ministry of Energy and its advisors are confident that sufficient bidders willing to develop the sites will line up.

Supposing that the bidding process proves successful and there will be no major obstacles to developing the sites, the first new hydropower plants would come on stream by 2014 - 15. The candidate sites are Oni (272 MW), Namakhvani (450 MW), Mtkvari (196 MW) and Upper Rioni (350 MW). The exportable output of these plants will depend on the future domestic load to be met and the available additional supplies from (rehabilitated) existing hydroelectric facilities and thermal plants.

As regards domestic electricity demand, it is assumed that the monthly loads will uniformly grow at 3% a year. Figure 1, Annex 4, shows the resulting potential for electricity exports in the period 2013 - 16, subject to the carrying capacity of the new transmission link with Turkey ( 730 GWh/month). According to this forecast, the annual electricity exports to Turkey would rise from 839 GWh in 2013, when the transmission line is expected to come on stream, to 4102 GWh in 2015, when the new hydropower plants are fully operational, and drop to 4,058 GWh in 2016 (because of the additional domestic load to be met). For the period beyond 2016, it is assumed that additional hydropower plants will meet the growth in domestic load so that the Georgian hydropower exports to Turkey remain at 4,001 GWh/year. No consideration is given to potential electricity supply from neighbouring countries that could be transmitted via Georgia to Turkey whenever the line is not fully loaded by Georgian exports and domestic energy flows (i.e., in the periods January - March and August - December).

The main assumptions concerning the costs of the project are summarized in Table 2, Annex 4. With respect to project finance it is assumed that total basic project costs will be financed with debt, while interest during construction (IDC) would be covered by equity to be raised by the project company. It should be emphasized that since the loan mix and the financing terms have not yet been determined, the figures used are illustrative in nature and, thus, do not reflect the arrangements that the potential lenders may offer.

Regarding the project revenues it is assumed that a uniform transmission/wheeling charge will apply to recoup the project’s costs, including those of the HVDC link with Turkey. Two options are considered:

A charge based on costs, including depreciation of capitalized project costs, taxes, interest and other allowable expenses, as approved by the regulator (accounting-cost-based tariff schedule)A tariff set at 10 EUR/MWh during the first 9 years of operation and at 5 EUR/MWh thereafter (front-loaded tariff schedule)

The downside of a tariff based on accounting costs is that it may call for a very high transmission charge when the line is poorly utilized. In fact, this problem arises under the base-case scenario since it expects a low loading of the line in the first year of operation. On the other hand, cost-based tariffs have the advantage that they militate against cash-flow problems caused by debt service obligations (unless loan repayments exceed depreciation). A frontloaded tariff schedule also helps coping with the high burden of debt service during the early years; it avoids tariff spikes, but tends to generate a higher return on capital than is necessary to recover lifetime average costs.

While the project might apply for and receive carbon credits, no such extra-revenues are considered under the base-case scenario.

The project’s weighted average capital costs (WACC) are used to compute levelised unit costs (LUC), i.e., the project’s lifetime average costs (EUR per MWh transmitted). Clearly, if the annual transmission tariff is based on accounting costs, the project’s internal rate of return (IRR) will be close to the WACC. Likewise, the IRR will exceed the project’s WACC if the imputed lifetime average tariff is greater than LUC.

Under the base-case scenario, the financial results look as follows:

Levelised unit costs amount to 5.07 EUR/MWh.With the frontloaded tariff schedule, the IRR works out at 9.63% and there would be a cash-flow problem in the first operating year.With a cost-based tariff schedule, the IRR is 4.92% and the project would have no cash-flow problem in the first year of operation.

Cost Overrun 20% 30%

WACC 6,28% 6,71%LUC (EUR/MWh) 6,87 7,71IRR with frontloaded tariff schedule 7,00% 5,88%Liquidity Problems Yes YesCost-based Average Tariff Revenues (EUR/MWh) 8,80 9,90Liquidity Problems No No

9 Sensitivity Analysis

The main financial risks to the project are:

Higher project investment costs than expectedDelays in the development and commissioning of hydropower plants in Georgia, resulting in an underutilization of the transmission line in the early years of operation Line congestion due to unexpected increases in domestic load flowsNo development of Georgia’s hydropower resources

Cost Overruns

Assuming that the total EUR-loan amount is fixed at the level of estimated basic costs (EUR 220 million), any cost overruns would have to be met with additional equity contributions (disregarding the option that the project company resorts to the local capital market).

If the basic costs turned out 20% higher than estimated, the LUC would rise to 7.00 EUR/MWh and the project would still break even with the front-loaded tariff schedule (IRR = 7.00% > 6.28 = WACC). However, the project company would experience a liquidity problem in the first year of operation that could be avoided with a cost-based tariff regime yielding average tariff revenues of 7.92 EUR/MWh and an IRR of 8.80%.

If there were a 30%-increase in basic costs, the LUC would rise to 7.71 EUR/MWh. Moreover, with the front-loaded tariff schedule, the project would not be financially viable (IRR = 5.88% < WACC = 6.71%). Financial viability could be achieved with a cost-based tariff schedule generating average tariff revenues of 9.25 EUR/MWh and an IRR of 9.90%.

In summary it can be argued that cost overruns of up to 30% could be absorbed through higher transmission charges without posing a severe threat to the profitability of hydropower exports.

Delays in Hydropower Development

As is shown in the above table, a delay in hydropower development of up to 3 years would not jeopardize the project’s financial viability under the assumed front-loaded tariff schedule, but it would saddle the project company with severe liquidity problems in the early years of operation. A cost-based tariff regime could ease the cash-flow problems, yet would come at the expense of a rather high transmission charges prior to the (delayed) commissioning of the hydropower plants.

If there were a considerable delay in commissioning new hydropower plants there is also the option to bridge the gap through thermal generation in Georgia and/or power purchases from neighbouring countries, provided these alternative sources of supply are competitive in the Turkish market.

Line Congestion

Line congestion poses no problem for the project’s economics in the winter period since in this period the base-case scenario assumes little line usage by power exports anyway. In the summer period, however, scarce transmission capacity would have to be allocated to power exports because guaranteed access to the export transmission capacity is essential to hydropower development in the first place.

No Hydropower Development

Cost-effectiveness is necessary for hydropower development; so the prospective sites will not be developed if the costs of doing so prove excessive. All the evidence suggests that these new hydros will be profitable; nevertheless, the risk that the sites will not live up to economic expectations cannot be eliminated. Likewise, it is possible that economically viable hydropower sites will not be developed due to perceived political/sovereign risks. A complete insurance against such risks is not available.

However, with and without Georgian hydropower exports to Turkey there should be opportunities for power flows from neighboring countries to Turkey that the transmission link in Georgia could facilitate. Based on its natural gas reserves, Azerbaijan is in the position to build new gas-based power plants with an exportable surplus of at least 3,500 GWh/year from 2015 onwards. So the potential electricity exports from Azerbaijan to Turkey could almost match the expected hydropower exports from Georgia. Needless to say, whether or not Azerbaijan will exercise this option is subject to the hard-to-predict future price differentials between the Turkish/Azeri gas and electricity markets (Azerbaijan has the choice between exporting gas or gas-based electricity). The same caveat applies to the potential for surplus power exports from Armenia, which will strongly depend on the availability and cost of gas imports from Iran and/or Russia. In any case, although the potential for regional power trade through the Georgian transmission link is no insurance against the risk of ending up with an underutilized line, it provides some comfort for the project.

Carbon Credits

Since there is no approved methodology in place that would allow the trading of the CO2-emission reductions rendered feasible by the line, it is difficult to predict if the project will qualify for carbon credits. It is worth noting, though, that revenues from emission trading would significantly improve the project’s financial outlook. Based on a baseline differential of 269 kg of CO2 per MWh exported from Georgia to Turkey (annual average of 1.06 million tons of avoided CO2), and assuming that the price for emission reductions is 5 EUR/t, the present value of the revenues from carbon credits under the base-case scenario

Delay in Hydropower Development (years) 1 2 3

WACC 4,81% 4,81% 4,81%LUC (EUR/MWh) 5,32 5,59 5,87IRR with front-loaded tariff 8,27% 7,11% 6,09%Multi-year cash flow problems Yes Yes Yes

would amount to EUR 70.3 million; at 10 EUR/t, the discounted revenues would be worth EUR 140.6 million, equivalent to 64% of the project’s estimated costs.

Higher Rate of Line Utilization

Arguably, the expected line utilization as per the base case scenario is on the conservative side (about 44% on an annual basis). It goes without saying that additional load flows during the winter period would improve the profitability of the project. For instance, with additional 500 GWh/year exported to Turkey, the LUC would drop from 5.07 EUR/MWh to 4.42 EUR/MWh, and under a frontloaded tariff schedule the IRR would increase to 11.68%, without posing liquidity problems.

Variability of Energy Exports

Since the output of the hydropower plants is stochastic, the annual energy available for exports to Turkey may deviate from the expected value, thus affecting the levelised unit transmission costs (other things being equal). To illustrate the point it is assumed that the present value of energy exportable to Turkey would be normally distributed with a coefficient of variation of 15%. The figure below shows the resulting cumulative probability/frequency distribution of the LUC based on 1,500 iterations. The graph suggests, for instance, that there is a 71% chance for the LUC to be below 5.50 EUR/MWh. Likewise, the probability that the LUC is 7.50 EUR/MWh or higher is less than 2%.

Cumulative Probability Curve LUC

0,00%

20,00%

40,00%

60,00%

80,00%

100,00%

120,00%

3,51 4,17 4,83 5,49 6,14 6,80 7,46 8,12 8,78 9,44 10,10

EUR/MWh

10 Institutional Arrangements

The institutional arrangements within Georgia for development and operation of the project are still under review by the Government of Georgia. The preferred arrangement will be communicated during the lenders’ appraisal mission.

Annex 1

1 Other Reports

1.1 General

The project idea is the subject of a number of studies on the Georgian/Regional Transmission System:

‘Feasibility Study for the Georgia High Voltage Transmission Lines Project’ by Kuljian Corporation (funded by USTDA)‘Regional Power Transmission Extension Plan for Caucasus Countries’ by Fichtner (funded by KfW)‘Potential export markets for Georgia electricity’ by ECON (commissioned by Ministry of Energy of Georgia)‘Power Transit Capability Analysis from Azerbaijan to Turkey’ by Georgian Centre for Transmission System Planning2 sponsored by USAID/USEA‘Electric power transit to Turkey from Russia/Armenia’ by GSE system group

The Kuljian Fichtner and ECON studies are reviewed in the following sections, while the GSE/GTU work is considered in Annex 6 – Load Flows and Dynamic Studies.

1.2 Kuljian Study

1.2.1 General

The project was the subject of a feasibility study by the Kuljian Corporation (funded by USTDA) which was completed in December 2007. This study concluded that the project “can reasonably be implemented into the existing MoE EHV network” and that “Given the ability to secure the requisite load case commitments contractually, and a reasonable level of capita cost control, the Project can be viewed as economically and financially viable.”

1.2.2 Assumptions and Conclusions

Specifically this study suggested the following:

Time Schedule of 36 months from contract awardSingle Turnkey ContractEstimated cost of US$ 311 millionAnnuity Tariff of $8.58/MWh for 100% Equity and $5.42/MWh for 70% debt financing for breakeven and 15% IRR

2 Cooperation between Georgian State Electrosystem (GSE) and Georgian Technical University (GTU)

The assumptions for the financial analysis include:

6.4% Interest Rate30 Year useful LifeThe Overhead Lines will be commissioned in 2012 while the HVDC Station will not be in service until 2015Depreciation over 12 yearsLoad Factor on the HVDC Link of 55% in summer and more than 90% in winterThe load flow cases included the following new generation sources Georgia:Khudoni (600MW)Gas Turbines in Batumi (80 MW)Namakhvani Cascade (250MW)Armenian 400kV Connection (240MW)

1.2.3 Cost Estimates

The cost estimate is developed as follows:

US$ MillionGardabani – Akhalsikhe 500kV Overhead Line 93.2Zestaponi – Akhalsikhe 500kV Overhead Line 31.5Akhalsikhe – Turkish Border 400kV Overhead Line 17.5Akhalsikhe 500kV Substation 20.0Akhalsikhe 400kV Substation 8.5Akhalsikhe 500/400kV, 600MW, back to back HVDC Converter Station

100.0

Extension of Gardabani 500kV Substation 3.0Reorganization/ Extension of Zestaponi 500kV Substation 9.0Contingency 10% 28.3Total 311.0Table 1-1: Kuljian Cost Estimates

1.2.4 Financial Analysis

Kuljian considered 2 scenarios for the financial analysis:

Scenario 1: 100% Equity FinancingScenario 2: 70% Debt Financing

Annuity tariffs were then calculated as the minimum tariffs that the project would need to charge its future customers over years in order to have the “required return” (15% IRR) and thus to be break-even. For each scenario 2 variations were analysed:

Variation A – HVDC + Link to Turkey IncludedVariation B – HVDC + Link to Turkey Excluded

For the purposes of this report Variation A will only be considered.

The results of the Kuljian cash flow analysis is summarised in Table 3-2:

Scenario 1A Scenario 1BAnnuity Tariff ($/MWh) 8.58 5.42Table 1-2: Kuljian tariff calculation

In this report the Internal Rate of Return (IRR) of a project is assumed to be the discount rate for Net Present Value of project cash flows equal to zero (NPV = 0) for 100% equity financing. For this reason the Kuljian tariff calculation for Scenario 1B is assumed to be for ‘break-even’ cash flow i.e. project NPV zero with a reduced IRR. Thus for IRR = 15% the required tariff is 8.58 $ / MWh for all cases in the Kuljian model.

1.2.5 Environmental Impact Assessment (EIA)

The Kuljian study included a preliminary Environmental Impact Assessment for the proposed project which concluded that:

“Overall, there does not appear to be major constraints from environmental impact considerations for the feasibility of the proposed transmission lines and Akhalsikhe substation project implementation.”

Although the assessment did not identify particular areas of concern it is still recommended that a detailed EIA study be carried out before work on the project begins. The assessment methodology is stated as being in accordance with Georgian Ministry of Environment Guidelines (though they do not address methodology for EIA) and World Bank/EDRB EIA protocols. Headings considered include:

Physical Impactsland use,water qualityair qualityflorafaunaSocio-economic Impactstrafficnoisepublic health (EMF)housing and utilitiescultural heritage / archaeology

Some preliminary findings are presented which suggest a low impact project where any potential concerns can be relatively-easily mitigated against.

A plan for a comprehensive EIA is presented in addition to a translation of the Georgian environmental regulations.

1.3 Fichtner Study

1.3.1 General

In November 2007 Fichtner issued a final report “Regional Power Transmission Extension Plan for Caucasus Countries (RTEP)”. This report reviewed 2 new international connections between Georgia and Armenia (Project 1) and Georgia and Turkey (Project 2). The report concluded that by implementing the projects Georgia would profit from and share in the development momentum gained by the neighbouring economies of Turkey, Iran, Azerbaijan and Russia. Other benefits expected from the projects included:

enhancement of power supply quality as a key factor for attracting foreign investments in industryenhancement of power system operating practice to the standards set by UCTE, thus creating prospects for inter-regional energy exchangescreating the physical prerequisites and organisational basis for further steps toward a competitive regional energy marketcreation of regional energy/electricity hub in Georgia

The time horizon assumed in the RTEP report for both projects is commissioning by 2015.

1.3.2 Technical Decision Criteria

For Project 2 (Turkish Connection) the study reviewed 6 options for the physical connection between the grids. Each option was technically evaluated using weighted multi-criterion analysis considering the following criteria:

Criterion WeightingMaximum Export Capacity 20%Investment Costs 25%Reliability of Turkish Export Path 10%Construction Lead Time 5%Expandability of RTEP 15%Reliability of National Supply 10%Flexibility of Trading Scenarios 15%Table 1-3: Fichtner Technical Decision Criteria

The cost estimates for the options ranged from EUR 72 Million (Option 1) to EUR 331 Million (Option 5).

Although Option 5 is the most expensive the analysis showed it to be the optimal solution from a technical point of view. This is due to the significant improvements in reliability of power supply, both for export and internal purposes.

Option 5 is then considered by Fichtner for economic and financial analysis.

1.3.3 Scope

The scope considered for Option 5 is:

New 500kV Connection Gardabani – AkhalsikheNew 500kV Connection Zestaponi – AkhalsikheNew 500kV Connection Enguri – AkhalsikheNew 500/400kV Station (with Back-to-Back HVDC) at AkhalsikheNew 400kV Connection from Akhalsikhe to Borchka

Note that this option is similar to the current project proposal except for the additional connection Enguri –Akhalsikhe.

1.3.4 Financial Analysis

For the financial analysis the following assumptions were made:

Export Capability only consideredAnnual O&M costs at 1.5% of investmentInflation is ignored30 year lifetimeDiscount Rate 8%Profit Tax 20%Load Factor 0.62Demand Growth 3% per annumExport of Energy to Turkey is only considered i.e. no transit in the analysisInterest Rate 6.4%

Georgia can export during 3 months 0.815 TWh or 5 months 1.358 TWh

The project is deemed feasible if it provides an investor with adequate return at a given tariff. This tariff must be at least as high as the financial levelised unit costs (LUC) – calculated as annualised project costs per kWh transmitted. Cash flow is then used to ensure adequate liquidity over the lifetime of 30 years.

For the purposes of cost allocation the project is divided into backbone components (the connections from Gardabani, Zestaponi and Enguri to Akhalsikhe) for domestic and export power and export only components (the HVDC plant and 400kV line to Borchka). Three scenarios are considered for cost allocation:

Scenario 1: No cost allocation between domestic and export components of energyScenario 2: All backbone component costs allocated to domestic use and export component costs to exportScenario 3: Costs allocated pro-rata between backbone and export components

The resulting calculation of LUC for 3 months export is:

S 1 S 2 S 3Total Dom Exp Dom Exp

Annualised Project Cost (€M) 33.6 21.5 12.1 13.5 20.2TWh 1.685 0.87 0.815 0.87 0.815LUC (€ cent/kWh) 2.0 2.48 1.48 1.55 2.48Table 1-4: Fichtner LUC Calculation

The subsequent cash flow analysis showed that at tariffs equal to the LUC calculated above, IRR (7.4% -7.8%) and ROE after tax (6.2% - 6.7%) values are not in line with what private investors would expect and therefore the study suggests tariff increases to 2.15 cents for domestic energy and 3.44 cents for export to make the project feasible – Scenario 4 in the report. In this case the IRR is 11% and ROE after tax is 10.7%.

1.3.5 Economic Analysis

The economic analysis concentrates on the main benefits described in the study:

Strengthening of the Georgian backbone transmission infrastructure and,Providing infrastructure for export to Turkey

Calculations are done to value avoided outages (reduction in undelivered energy), technical loss reduction and trading benefits. For outage and loss reduction the study calculated the following benefits:

Cost per kWh €M per annumAvoided Outages €0.4 5.9Loss Reduction €0.02 2.3Table 1-5: Fichtner Benefits of Outage and Loss Reduction

Note that the economic cost of power outages of EUR 0.4 per kWh is based on a USAID study – ‘Energy Balance of the Power Sector of Georgia’, August 2006.

The trading benefits to the Georgian economy are calculated with the following assumptions:

Export is 0.815 TWh per annumWholesale tariff in Turkey is EUR 0.0563 per kWhCost of generation in Georgia is EUR 0.02 per kWh

The following table summarises the findings for three cases:

Case 1 Case 2 Case 3Export Tariff (€/kWh) 0.0563 0.048 0.0563Export Energy (TWh) 0.815 0.815 0.556Annual Benefit (€M / annum) 29.6 20.2 20.2Project Cost Allocation (€M / annum) 20.2 20.2 20.2Trading Profit (€M / annum) 9.4 0.0 0.0Table 1-6: Fichtner Trading BenefitsThe results show that the minimum tariff required at the Turkish border to pay for the export component of the project is 4.8 EUR cents per kWh while the minimum export at 5.63 EUR cents per kWh (for the samebreak-even) is 0.556 TWh.

1.4 ECON Study

The ECON studies were commissioned by the Georgian Ministry of Energy to analyse the potential trading markets for electricity in the Caucuses region. The first report resulted from a general review of the electricity sectors in Armenia, Azerbaijan, Iran, Russia and Turkey and provided preliminary conclusions on the feasibility of exports to these markets from new hydro generation in Georgia. The second report is a more detailed analysis of the Turkish and Azerbaijan sectors and discusses the possibility of transit from Azerbaijan to Turkey in addition to export of new Georgian hydro. The reports’ conclusions can be summarised as follows:

Russia: While it may have seasonal needs in the region, its medium/long term goal is to export to Turkey and other countries. Therefore it is not regarded as a serious export market for Georgian hydro. However, if Russia wishes to export to Turkey then transit through Georgia is an attractive route.Armenia: Not regarded as a serious export market for Georgian hydro due to overcapacity, cheap gas prices and plans for a replacement nuclear plant. As in the Russian case though, this overcapacity could be exported to Turkey via Georgia.Iran: Potentially a summer market for Georgian power transmitted through Armenia in the medium to long term. With planned additions to the Armenian grid this will be possible.Azerbaijan: A power sector in transition; generation capacity is growing while demand is falling due to increased (and more realistic) tariffs and improved metering leading to increased collections. It is therefore expected that Azerbaijan would have spare capacity which could be exported but the analysis is complicated by the future uses of Azeri gas resources - local heating / local generation / export potential, and the opportunity costs of not exporting gas at world market rates.Turkey: Demand has been growing at 6-7% and the increased load shedding is expected up to 2012 as the system struggles to meet the demand. Wholesale prices were average 11.6 USc/kWh in April 2008. The wholesale price is expected to remain high unless gas/oil prices reduce significantly and/or a substantial expansion of lignite plants is approved. Turkish authorities have expressed interest in a connection to Georgia (to add to new EHV connections under construction to Bulgaria/UCTE). Contracts could be negotiated with the state entity Tetas or private wholesale companies operating in the sector.

1.5 Comments

The Kuljian and Fichtner studies considered only Georgia’s export potential in their load flows and financial assessments. Indeed both considered the availability of Khudoni and Namakhvani as part of the assessment. The ECON reports concentrate on the potential markets for transit through and export from the Georgian system.

From a technical point of view Kuljian considered only one technical solution, whereas Fichtner considered and evaluated various technical solutions for Georgia’s connection to Turkey at Akhalsikhe. The result of the Fichtner analysis (the optimum solution) is Option 5 which is the current project plus an additional connection between Akhalsikhe and Enguri. As will be seen in Annex 6, this additional connection, while being desirable for reliability reasons, is not necessary without the additional generation which would be provided by Khudoni.

A comparison of other parameters in the current and previous studies is shown in Table 3-7 below:

Kuljian Fichtner CommentInterest Rate 6.4% 6.4%Depreciation 12 Years 30 YearsDiscount Rate 9% 8%Link Energy Transfer

4.6 1.358 TWh See note below

Load Factor 74% 65% Kuljian not explicitly stated: see note below.

Table 1-7: Study Parameter Comparison

The transfer capacity of the Turkish Link is evaluated differently in the reports. Kuljian assumed that the link would handle its line capacity at a load factor of 55% in summer and 90% in winter, with 95% availability. It is not clear from the report what this means but assuming the following:

Link capacity = 720MWLoad factor 55% (summer) – 4 monthsLoad factor 90% (winter) – 8 monthsAvailability = 95%

Then annual energy transmitted = 4.6 TWh

Fichtner calculated an export potential based on current plus new build hydropower. The Fichtner study is based on analysed power flows without transit. Fichtner also has higher Capex due to the additional line from Akhalsikhe to Enguri.

The transfer capacities in this report are based on load flow studies performed in house by GSE, both for export and transit. The 400kV line will be designed to accommodate the maximum transfer capability calculated (up to 1000MW).

Both Fichtner and Kuljian calculated the Levelised Unit Cost (LUC) required to deliver a stated return on the investment for the shareholder – using internal rate of return (IRR). The results are summarised in Table 3-8.

Kuljian1A

Kuljian2A

Fichtner Fichtner Comment

Capex (€M) 242 242 303 303

Equity (€M) 242 80 96 96 Kuljian 2A: 70/30Fichtner: Equity = 30% + Interest on WiPThis Report: Equity = Interest on WiP

Debt (€M) - 188 212 212Total Finance (€M) 242 268 308 308Fees (€M) - 26 5 5IRR 15% * 7.8% 7.8% *This value is

not clear – see note in 3.2.4 above

TWh 4.6** 4.6** 1.685 2.228 **Kuljian not explicitly stated

Export / Domestic / Transit

Export Export Export + Domestic

Export + Domestic

Tariff/LUC (€cent/kWh)

0.64 0.4 2.0 1.51

Annual Income (€M)

29 18 34 34

Income/Finance 0.122 0.069 0.109 0.109 = Annual Income / Total Finance

Table 1-8: Tariff calculation comparison

The calculated ratio Income/Finance is an attempt to compare the 2 valuations of the project.

The Fichtner analysis is based on low export volumes and delivers a less than satisfactory IRR. Higher tariffs would be required to deliver IRR greater than 10% at these energy values.

Annex 2: The Turkish Electricity Market

This section of the report will provide an overview of the organisation of the Turkish market, and review current and projected supply and demand for electricity, as well as the expected prices in the wholesale electricity market.

2.1 Sector OrganizationThe Turkish electricity sector is in large part deregulated. In 2001, the government enacted the Electricity Market Law that ushered in structural reforms in the electricity sector. The law separated TEAS, the state-owned generation- and Transmission Company, into three state-owned companies responsible for

Generation, run by Turkish Electricity Generation Company (EUAS)

Transmission, run by Turkish Electricity Transmission Company (TEIAS)

Wholesale, run by Turkish Electricity Trading and Contracting Company (TETAS).

While the responsibility for electricity transmission will remain with TEIAS (monopoly), the private sectoris envisaged to play a larger role in generation, trading and distribution of electricity. The new Electricity Market Law also initiated the establishment of the Energy Market Regulatory Authority (EMRA) in 2001. The main tasks of EMRA are to monitor the power sector, natural gas and petroleum markets, including issuing licenses, setting tariffs and ensuring competition by eliminating vertically integrated state monopolies and allowing participation of the private sector in Turkey’s energy sector. The Ministry of Energy and Natural Resources is responsible for overall policy in the sector.Figure 2.1: Structure of Turkish Electricity Sector

The Turkish electricity sector is currently in a stage of transition towards a fully deregulated market. EUAS still own approximately 40% of the generation capacity in Turkey. As part of the deregulation plans for the sector, it is envisaged that no private sector company will control more than 20% of total generation capacity3. EUAS’s thermal and small hydro assets have been separated into portfolio companies and will be privatized. EUAS will only retain the large hydro power plants in Turkey in its portfolio.The wholesale market for electricity is partly deregulated. The price for electricity provided by EUAS is regulated and tends to be low, as most of its asset base is depreciated hydro assets with low marginal cost. There is a competitive market for privately generated electricity where TEIAS organizes an auction for hourly generation capacity for the following day. The EUAS’s regulated cost and the hourly competitively tendered privately provided electricity is averaged and makes up the electricity price that TEIAS uses for on sale to TEDAS and the private distribution company. The wholesale market for electricity is expected to be fully deregulated by 2012, although the date for full deregulation has been extended several times in recent years. Much of the electricity generation takes place in the Eastern part of the country while the consumption is in the West and South. Transmission of electricity in Turkey is controlled by TEIAS. The transmission grid in Turkey is extensive and has low losses (around 3%), despite long transmission lines. It is possible for private sector companies to build new transmission capacity. The transmission tariff for usage of such a tariff will be regulated by EMRA. A maximum of 50% of the capacity in the line will be reserved for the company that builds the transmission line until the cost of financing the line has been recovered. The distribution sector is in the process of being privatized. TEDAS, the state owned distribution company, has been separated into 20 regional companies. A private distribution company operates one distribution region in Turkey. The tender for the privatisation of state-owned distribution companies is expected to take place before 2010. Companies with an annual consumption in excess of 3 GWh are allowed to freely choose their supplier of electricity.

2.2 Electricity DemandThe demand for electricity in Turkey has increased by an average of 8% per annum since 1960. A growing population and strong per-capita economic growth have fueled the surge in demand. Demand growth has been particularly rapid in recent years partly due to a booming economy but also because of a significant erosion of the real tariff level to end users in Turkey. Industry consumed approximately 40% of total electricity in Turkey in 2007, the residential sector approximately 25% and the commercial and public sector 35%.The demand for electricity is expected to increase rapidly in the coming years. TEIAS has made a high and low forecast estimating that the demand will increase by 6–7.5% on average annually to 2016 (see table 2.1).

Table 2.1 Electricity Demand Projections until 20162008 2009 2010 2011 2012 2013 2014 2015 2016

Demand scenario 1 TWh 203,8 220,7 239,0 258,9 280,1 302,5 326,4 351,8 378,2Demand scenario 2 TWh 196,7 209,1 222,3 236,3 251,1 267,0 283,8 301,9 321,6Demand growth scenario 1 TWh 15,4 16,9 18,3 19,8 21,2 22,4 23,9 25,5 26,4Demand growth scenario 2 TWh 11,7 12,4 13,2 14,0 14,9 15,8 16,8 18,2 19,6

Source: TEIASDemand for electricity generation is expected to grow by between 137–190 TWh in the decade to 2016 doubling the need for generation capacity in Turkey. The demand growth in 2016 alone is estimated to 19–26 TWh. Several factors may alter the demand scenario - closely linked to development in GDP per capita in Turkey. A significant adjustment of end user prices for energy may slow the growth in demand. A prolonged slowdown in economic growth would have the same effect. The economic crisis in 2001 saw a fall in the electricity consumption in Turkey. More effective management of the distribution sector, which currently experiences technical/commercial losses of approximately 17%, compared with 5–7% in many EU countries, may also reduce demand for generated electricity. But the trend, over the last five decades, of steadily increasing demand is likely to continue. The average Turkish citizen consumes only one third as much electricity as the average EU citizen and demand is expected to grow as GDP per capital catches up with the EU countries.

3 Please see Electricity Market Law Turkey Law Section 2, article 2

2.3 Generation MixTurkey has limited domestic energy resources and has become increasingly dependent on imports to fuel its rapidly growing demand for electricity. The most significant domestic energy resources, which are currently proposed for development, are hydropower and low quality lignite coal. The development of the fuel mix in Turkey from 1971 to date is illustrated in the graph below. Most of the generation expansion from 1990 onwards has come through a rapid growth in gas-based generation using imported gas, mainly from Russia. The private sector has driven the expansion of gas-based generation, which is characterized by low capital and high fuel costs compared with other generation technologies.

Figure 2.1: Fuel Mix Development in Electricity Generation, 1970–2005

2 Source: International Energy Agency

TEIAS has also made projections for the energy mix for electricity generation in Turkey to 2016. The projections include existing generation, projects under construction and projects that have received government approval for development.As can be observed in figure 2.3, the Turkish electricity market is experiencing an increasing mismatch as supply has struggled to keep up with surging demand. The situation is expected to deteriorate further in the coming years, resulting in increased load shedding.

Figure 2.3: Demand and Fuel Mix Development, 2006–2016

Coal

Oil

Gas

Hydro

Other

Demand (scenario 1)

Demand (scenario 2)

0

50

100

150

200

250

300

350

400

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

An

nu

al g

ener

ati

on

TW

h in

Tu

rke

y

3 Source: TEIAS

Most of the gas used to generate electricity in Turkey comes from Russia and is piped across the Black Sea, with Azerbaijan and Iran being other suppliers. The increase in gas-based generation has exposed the Turkish private wholesale electricity market heavily to a sharp increase in oil and gas prices. The average gas price in Turkey in 2008 is expected to be 223 Euro/tcm, giving a generation cost from gas fired power stations of 5–9 Euro c/kWh depending on the thermal efficiency of the plants (29–56%). Given the growing security of supply concerns that increased gas based generation creates among Turkish policymakers and the significant importation of inflation through the increasing price for gas, the government in Turkey is interested in slowing the growth in the use of gas as feedstock for power production.An expansion of the utilisation of hydropower resources is seen as one way of reducing the exposure to gas. A significant hydropower expansion is underway in Turkey. Between 2006 and 2008, the Turkish

Hydropower Planning Agency (DSI) auctioned, to the private sector, the rights to develop a total of more than 7,500 MW of new hydro capacity with expected annual generation in excess of 27 TWh. Since not all of the sites will be developed, TEIAS estimates total hydropower generation in Turkey to be 67 TWh in 2013. Turkey will then have utilized the most economically feasible half of its potential. It is also worth noting that because of climate change, generation of electricity from existing HPPs in Turkey is expected to decline by 10% by 2020, especially affecting the HPP sites in South Eastern Turkey4. The generation licenses for new hydropower facilities are tendered for by DSI. Qualified private sector companies bid on the highest water usage tax they are willing to pay to DSI per kWh generated. The DSI tax fluctuates significantly depending on how attractive the hydropower site is for developers. The tenders have attracted significant interest. Twenty one companies participated in the tender for the 240 MW Cizre Baraji HPP site in January 2008 which attracted a bid of 3.7 Euro c/kWh from Aydınlı Enerji -the winning company. Econ estimates that this project needs a levelized tariff of at least 6.7 Euro c/kWh to offer a reasonable return for investors. The 19 MW Catak HPP in the Rize region in Turkey fetched an all time high DSI tax charge of approximately 4,1 Euro c/kWh in a tender in May 2008. The DSI tax is expected to increase further if the oil and gas prices continue to increase on world markets. The government of Turkey is, therefore, taking out most of the expected difference in the cost between the cost of generating electricity from HPPs and the long run marginal cost in the electricity system, through heavy taxation of HPP plants.

4 See Europe’s hydropower potential today and in the future: Bernhard Lehner etc 2001

Table 2.2: DSI Tax Charge Greenfield HPP Developments, 2006–2008Project name Installed capacity MW Annual production GWh Load factor % DSI tax Euro c/kWhCizre Barajı ve HPP 240 1 208 57,5 % 3,68Dereköy-Demirkapı HPP 105 366 39,8 % 3,43Çamlıca HPP 110 376 39,0 % 3,37Alara Enerji Grubu HPP 187 622 37,9 % 3,06Narlı HPP 130 402 35,3 % 2,78Kayraktepe HPP 290 768 30,2 % 2,50Aksu-Anakol HPP 120 344 32,7 % 2,49Kavşakbendi HPP 140 652 53,2 % 2,34Çetin Bar. Ve HPP 350 1 237 40,3 % 1,91Arkun HPP 222 790 40,6 % 1,68Silvan Barajı ve HPP 160 681 48,6 % 1,36Silopi Enerji Grubu HPP 140 356 29,1 % 0,82Alkumru Bar.HPP 222 812 41,8 % 0,55Sami Soydam Bar.HPP 175 515 33,6 % 0,42Ayvalı (Çoruh) HPP 125 409 37,4 % 0,28Kemah Bar ve HPP 135 494 41,8 % 0,04Dilektaşı Bar.HPP 125 328 30,0 % 0,04Karakurt HPP 110 342 35,5 % 0,02Average 171 595 39,1 % 1,71

Source: Econ calculations based on information from DSI using a Turkish Lira/Euro exchange rate of 0.5431Due to the rapid increase in the price of oil and gas, coal generation based on domestic lignite and imported hard coal has become more attractive. But with the prices of Australian hard coal, following the prices of oil and gas upwards and approaching 100 Euro/tonne in June 2008, an increase of 50% from 20075, generation cost of new coal fired generation based on imported coal is approaching 6-8 Euro c/kWh. As a rule of thumb, an increase of hard coal prices of 25 Euro/tonne will increase generation cost for coal fired power plants by approximately 1 Euro c/kWh. Domestic lignite is the least cost expansion alterative for Turkey, provided that no price is set on carbon emissions. Turkey has reserves of at least 8.1 bn. tonne of mostly low quality lignite. 80% of remaining reserves have a calorific value of less than 2,500 kcal/kg6. Using domestically produced lignite for power generation will mitigate the increasing security of energy supply concerns for Turkish policymakers and lower the cost of generating electricity. The Turkish government intends to expand lignite production significantly in the coming years. A total of 5,000 MW of new domestic lignite generation capacity is planned. This could produce as much as 38 TWh of electricity annually, an increase of approximately 20%7. In order for lignite to substitute for gas based generation in any meaningful way, Turkey needs to build at least 10,000 MW in new capacity by 2016 in addition to the 5,000 MW currently planned8. The lignite generation expansion will take place despite strong local opposition to the construction of new plants, EU accession requirements which sets strict requirements on emissions from the power sector and possible post Kyoto CO2 emissions reduction commitments. A significant lignite coal generation expansion could be seen as a last resort option for an energy system squeezed between rapidly rising energy costs and growing energy security concerns. A significant expansion of lignite production could replace gas as base load production in Turkey and reduce base load generation cost. However, domestic lignite prices have tended to move up with the price of imported coal and gas and the cost advantage of domestically produced lignite is uncertain in the medium and long run.In addition to hydro and domestic coal, the government in Turkey intends to rely on nuclear energy to meet the future energy demand. A tender was published in the spring of 2008 to construct a 3,000–5,000 MW nuclear power plant9 with several other power plants at the planning stage. A 4,000 MW nuclear power plant could produce as much as 30 TWh annually. However, it may take as much as 10 years from tender close to the nuclear power plant can be commissioned and the cost of nuclear energy may be approximately 5-7 Euro c/kWh on a levelized basis depending on the cost of capital.In summary, the rapid increase in demand for electricity in Turkey is expected to be met a combination of tapping domestic hydro resources to meet peak demand, and expanding domestic lignite and nuclear

5 Please see Global Coal RB index for details www.globalcoal.com6 Please see Resources, quality and economic importance of solid fossil fuels in Turkey 2004 http://popups.ulg.ac.be/Geol/docannexe.php?id=14687 Assuming a thermal efficiency of 40%. 8 This observation is shared by Hayati Cetin the head of project approval department in the Ministry of Energy and Minerals in Turkey in email correspondence with Econ 17/6 2008. 9 See http://www.tetas.gov.tr/nukleer/eng/nklr.htm for details.

production to meet base load demand. Additional natural gas generation may also be expected if gas prices reduce or as a short term solution to the growing deficit.However, provided that electricity can be produced at a competitive price, there should be room for significant imports of electricity to Turkey. The import of electricity on the proposed link from Georgia would constitute 1–3% of the total electricity consumed in Turkey in 2013 and would therefore not be expected to have a material impact on prices in Turkey. Figure 2.4 below represents a best-case schedule for new lignite and nuclear electricity generation capacity in Turkey. If the demand growth does not moderate, Turkey is likely to become more reliant on gas fired power stations and/or load shedding to balance supply and demand in the period to 2016.

Figure 2.4: Electricity Balance with Confirmed Projects and Imports in 2016

4 Source: TEIAS and Econ calculations

2.4 Electricity PricesWholesale electricity prices have moved up sharply in the Turkish market in recent years. This is largely a result of a significant increase in the price of imported gas. Figure 5 below shows the average monthly prices in Turkey on an hourly basis for the period May 2007 to May 2008. With the exception of January and February 2008 where prices on average remained above 6.7 Euro c/kWh throughout the day, the prices dipped during the night time (1 AM to 7 AM) and remained high for the rest of the day. Prices in this period are largely set by gas based generation and have been in the range of 7-9 Euro c/kWh in 2008. In the low load period during the night, the prices are set by base load domestic lignite electricity generation and the prices fall to 2.7–4.7 Euro c/kWh. The average private wholesale electricity price in Turkey increased by 13% in Euro dollar terms from March-July 2007 to March-July 2008 to 7.9 Euro c/kWh

Figure 2.5 Private Wholesale Electricity Prices March 2007–July 2008

0,00

1,00

2,00

3,00

4,00

5,00

6,00

7,00

8,00

9,00

10,00

mar

.07

apr.0

7

mai

.07

jun.

07jul.0

7

aug.

07

sep.

07

okt.0

7

nov.0

7

des.

07

jan.

08

feb.

08

mar

.08

apr.0

8

mai.0

8

jun.

08jul.0

8

Av

era

ge

pri

vat

e w

ho

les

ale

pri

ces

in T

urk

ey E

uro

c/k

Wh

Source: Econ calculations based on PMUM prices

2.5 Import/Export of Electricity to TurkeyTurkey is currently not trading significant amounts of electricity with neighboring countries. The country imported 636 GWh in 2005 and exported 1.8 TWh, or less than 3% of annual consumption, mainly to Iraq. However, this will change when the interconnectors currently under construction to Bulgaria and Greece arefinalised by 2012. The transmission capacity westwards will increase to approximately 2000 MW or up to 17 TWh annually. This interconnection capacity may have an impact on the development of the electricity prices in Turkey although Turkey’s neighboring countries in the EU are facing the same input prices to generate electricity as Turkey.10. Import and export of electricity to Turkey is liberalized. Both TETAS, the state owned wholesale trading license holder, and the 25 privately held wholesale trading license holders are allowed to import and export electricity to/from Turkey through the high voltage grid. In interviews with Econ in Ankara in May 200811, Budak Dilli, General Director of Energy Affairs in the Ministry of Energy and Minerals in Turkey, stated that the Ministry had a strong preference for private solutions for import of electricity and ruled out TETAS providing any long term guarantees for purchase of electricity from neighboring countries including Georgia. Mr. Haci Duran Gokkaya, the General Manager in TETAS seemed more interested in entering into long term power purchase contracts in discussions with Econ during the same visit, but as TETAS will take their instructions from the Ministry on these issues, it is uncertain to what extent the TETAS position is relevant. Of the private companies that hold a wholesale license, there are several large multinational companies with headquarters in Turkey. Some of the largest license holders are listed in the table below. They would clearly be credible counterparts for a Georgian company seeking to export power to Turkey.

Table 2.3: Selective Turkish Companies with Wholesale Trading License

10 One example is the projected 2000 MW Belene nuclear reactor project in Bulgaria. The project is projected to cost approximately 5 bn. Euro or approximately 0,33 Euro/kWh generated (Financial Times 23 June 2008)

Name of company Annual turnover Contact details

Enerjisa Elektrik (fully owned by Sabanci Group

9,9 bn. Euro (Sabanci 2007) www.sabanci.com

Zorlu Electric Enerjisi 3,5 bn. Euro (2005) www.zorlu.com.tr

Ak Enerji 112 m Euro (Ak Enerji 2006) www.akenerji.com.tr

Econ met with several energy companies in Ankara in May 2008 that indicated an interest in acting as wholesale traders for electricity imported from Georgia. However it is uncertain to what extent these companies are willing to provide long term power purchasing contracts to sellers of electricity from Georgia. This has to be negotiated individually by the developer of projects in Georgia/Azerbaijan and the private wholesale traders. EMRA has issued regulations for import and export of electricity to Turkey12. The regulations specify the conditions that need to be fulfilled in order for an entity to engage in import/export of electricity. The criteria include:

Ability to operate the national electricity system in a parallel with the counterpart system

Ability to operate a generation facility or a unit of a generation facility in the country in parallel to the importing system

Operation in islanded mode

Ability to establish asynchronous parallel (DC) connection.

The regulation also stipulates that information be submitted about the source, duration and quantity of electricity that will be imported.Applications for import/export of electricity will be reviewed by the Ministry of Energy and Natural Resources, and the opinion will be taken from TEIAS regarding the transmission capacity on the Turkish side of the border. If the opinion is positive, the application will be posted on the website to the Ministry of Energy and Natural Resources.In an interview with Econ in Ankara in May 2008, Mr. Kemal Yildir, Assistant General Manager in TEIAS confirmed that there is capacity to receive approximately 1000 MW in Borchka in Turkey but that it would be difficult to increase the export volume beyond 1000 MW without constructing additional transmission capacity from Borchka to Central and Western Turkey. TEIAS will undertake a competitive tender to price the usage of the capacity if there are more companies that want to utilize the capacity in an interconnection transmission line than there is capacity in the line. EMRA rules states that companies that want to utilize the capacity in the line need to get an approval from the Ministry of Energy in Georgia. In other words, the Georgian Ministry of Energy can to a large extent determine the electricity tariff for export of electricity to Borchka from the Georgian grid. If the Ministry of Energy in Georgia does not approve export of more than 1000 MW (the assumed capacity in the line) there will be no tender on the Turkish side and therefore a regulated transmission tariff. 2.6 Feasibility of Electricity Imports from Georgia Turkey is expected to experience significant shortages in its power sector in the medium term. The Ministry of Energy and Minerals in Turkey indicated a strong interest in imports of electricity from neighboring countries, including Georgia to help make up the shortfall.Approximately 1,000 MW of available transmission capacity is available from Borchka in Turkey to transport imported electricity South and East in Turkey. In other words, it will most likely at this stage only justify one 400/500 kV line from Georgia to Turkey in the short/medium run without expanding the transmission capacity on the Turkish side from Borchka. The prices in the Turkish private wholesale market are high at present and are expected to remain high as long as oil/gas prices stay above 80 USD/barrel as shortages persist. The Ministry of Energy and Minerals in Turkey wants the Turkish private sector to act as wholesale traders for import of electricity from Georgia and will not provide any long term power purchase agreement (PPA) through state owned TETAS. It is uncertain to what extent the private sector is willing to provide long term PPAs as the electricity wholesale market in Turkey is in transition and operates as a spot market at present.

12 http://www.emra.gov.tr/english/regulations/electric/import/import.doc

Because of the very heavy taxation on new HPP sites for development (up to 3,7 Euro c/kWh in DSI water usage tax alone), the most prospective large scale Georgian HPP sites have a significant cost advantage compared with Turkish HPP sites.

Annex 3: Potential for Electricity Exports from Georgia to Turkey

Georgia has one of the largest untapped hydro resources in Europe. The technical/economic potential is estimated to up to 60 TWh of which approximately 8 TWh, or less than 15% of the potential, has been developed. But the country has struggled to attract private sector capital to develop the resources. There are several reasons for this, but the principal reason is that the tariff levels in Georgia and neighbouringcountries, that are connected with Georgia with significant transmission capacity, (Azerbaijan, Russia), have been too low to support new investments.

3.1 The Georgian Electricity SectorGeorgia has a deregulated electricity sector which has experienced an impressive improvement in performance since 2004. The sector is deregulated and unbundled into generation, transmission and distribution companies. An independent regulatory authority supervises the sector and is responsible for tariff setting, while the mandate of the Ministry of Energy is largely confined to policy-related matters. Generation assets are owned in part by the Georgian state and municipalities, but by private interests as well. Generation of electricity is dominated by hydropower plants (HPPs), while gas-fired power stations and

imports meet peak and winter demand. Georgia was a net exporter of electricity in 2007, mainly due to exports in the summer time. An Energy System Commercial Operator (ESCO) is responsible for the balancing market for contracting for electricity export and import. It is a commercial entity owned by the Georgian state, though the Government plans to privatize it in the coming years. The backbone of the transmission grid is the 500-kV line connecting the main generation assets in Georgia with the Russian transmission network. The line is jointly owned by RAO UES (50%) and the Georgian state (50%). The government also owns the transmission company, Georgian State Electrosystem (GSE), which is responsible for the 220/330kV main system in addition to some 110/35kV non-privatised assets. GSE is also the System Operator. The Czech company Energo Pro, through the ownership of UEDC, owns some system 110kV lines.There are three distribution companies in Georgia. Two have approximately 1 million customers each: Telasi (responsible for Tbilisi and 75% owned by RAO UES) and UEDC (responsible for distribution outside Tbilisi and fully owned by Energo Pro). Kakheti Distribution Company is a smaller distribution company, operating in the east of the country. There is also a state-owned distribution company in Abkhazia, outside the control of the central Government in Tbilisi.

Figure 3.1 Structure of Georgian Electricity Sector

3.2 Generation CapacityGeorgia is largely a hydro based system. The total installed hydro capacity is approximately 2820 MW. In addition, approximately 650 MW of thermal gas fired generation is connected to the system of which 110MW is a modern gas turbine (in open-cycle) installed in 2006. In 2007, hydrogenation constituted approximately 78% of total electricity in the system, thermal generation 17% and imports approximately 5%. Approximately 8% of the generated electricity was exported, primarily in the summer months, when the load is low while hydro generation is at its peak due to the seasonal patterns of the river flows in Georgia.

Figure 3.2: Generation profile and exports Georgia 2007

Hydro generation

Thermal generation

Import

Load curve

0

100

200

300

400

500

600

700

800

900

1 000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

GW

h p

er m

on

th

Source: ESCO

Georgia exported approximately 625 GWh of electricity in 2007 according to ESCO, much of it on swap contracts with neighboring countries where excess summer generation was swapped with winter generation. The net export was 192 GWh.

3.3 Wholesale electricity prices in GeorgiaA comparison of the wholesale electricity price in Georgia and Turkey is shown in Figure 3.3. While the average wholesale tariff for privately produced electricity in Turkey was 7,8 Euro c/kWh in the periodAugust 2007 to July 2008 and 9,3 Euro c/kWh in July 2008, the average price in the same period in Georgia

was 2,5 Euro c/kWh. In Georgia, the tariff fluctuates significantly between the summer months, when there is a surplus of electricity in the system and limited export options and the winter months. The winter generation cost in Georgia is expected to increase further as the cost of imported gas increases in the coming years.

Figure 3.3: Wholesale prices electricity in Turkey and Georgia, March 2007–July 2008

Turkey private w holesale tariff

Georgia balancing tariff ESCO

0

1

2

3

4

5

6

7

8

9

10

Wh

ole

sa

le p

ric

e E

uro

c/k

Wh

Turkey 5 ,45 6,17 5,77 6,50 7,26 6,82 6,11 6,01 7,41 7,69 9,09 9,01 8,25 7,74 8,32 8,03 9,33

Georgia 2 ,38 2,52 1,72 1,74 0,89 1,74 2,85 3,64 3,72 4,04 3,75 3,85 2,90 1,19 1,53 1,53 1,15

March Apr il May June Ju ly AugustSeptem

berOctobe

rNovem

berDecem

berJanuar

y Februa

ryMarch April May June July

5 Source: Econ calculations

3.4 Load ForecastThe Georgian economy has been growing rapidly in recent years without a noticeable increase in the demand for generated electricity. In 2007, when the economy grew by 12.4%, demand for generated electricity increased by approximately 3%. This is largely due to the rapid energy efficiency improvements in the sector as the transmission and distribution losses have come down significantly. However in the medium term, the load growth is expected to pick up as economic growth leads to higher demand for energy. Econ Poyry has made some estimations of the annual load growth to 2016 based on a base case where the GDP per capita will grow by 6-8% per annum to 2016 and the demand for generated electricity will increase 25% as fast as GDP growth. This is in line with the observed demand growth in 2007. The exp