bstp-gse project design

8/8/2019 BSTP-GSE Project Design

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Black Sea Regional Transmission Project

Project Design

GSE

September 2008


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1 Project Objectives

Georgias power generation potential comes from both renewable sources of energy including hydro andwind power and from thermal generating capacity. Its hydro-power potential is estimated at up to 80 billionkWh 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 89.5 billion kWh p.a. (i.e. 15% of theeconomically 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 isenvisaged. 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 Georgiasenergy resource is located in the Northwest, while two thirds of the domestic demand is located in easternGeorgia, and most of the potential export market is located in countries south of Georgia (e.g. Turkey, Iranand Iraq, all of which experience rapid economic development and growth in electricity demand). Powerdelivery to these markets requires a reliable high voltage transmission network. At present only one strongline 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 inthe East, including frequent total system blackouts. Apart from reducing domestic grid reliability, this alsolimits 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 fromAzerbaijan 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 linksfrom 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-BackHVDC link at Akhalsikhe and a 400kV overhead line. The line construction will be divided between theGeorgian side (~20km) and the Turkish side (~130km). The Turkish investment is estimated to be 45million.

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 ofGeorgia)Power Transit Capability Analysis from Azerbaijan to Turkey by Georgian Centre for TransmissionSystem Planning

1sponsored 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 consideredin Annex 6 Load Flows and Dynamic Studies.

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


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


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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 Substationin 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 thisconnection was built in the late 1980s but needs restoration/rehabilitation. The remaining 137km will benew construction.Completion of 500kV overhead transmission line between existing Zestaponi 500kV substation toAkhalsikhe 56km of single circuit line with 15km double circuit entry to Akhalsikhe. Approximately17km of this connection was built in the late 1980s but needs restoration/rehabilitation. The remaining54km 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 GSEs SCADA system to accommodate the new infrastructure.


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3 Benefits

The project will benefit both Georgia and the local region by increasing the reliability of the Georgian EHVbackbone 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, importand 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 useof 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 theadditional energy through its network and increased reliability of the main system reducing undeliveredenergy and hydro generators and other Independent Power Producers (IPPs) will be provided with thenecessary 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 thereliability of the power supply from west to east in Georgia. Undelivered energy due to 500kV faults (andindeed some 220kV outages) will be reduced.

In 2007 the undelivered energy due to faults on the 500kV system (excluding the Imereti Line) was 1.2GWh. At an outage cost per kWh suggested by Fichtner (EUR 0.4) this represents a loss to Georgia of EUR480,000 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 permanentfaults per 100 km years):

Line name Length(km)

Fault Rate(per 100km-year)

ExpectedFaults/Annum

Imereti 130 0.4 0.52

Kartli I/II 340 0.4 1.36

Total Equivalent beforenew Project

490 0.4 1.88

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


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Line name Length(km)

Fault Rate(per 100km-year)

Expected Faults/Annum

Imereti 130 0.4 0.52

Kartli I/II 340 0.4 1.36

Akhalsikhe - Gardabani 205 0.4 0.82

Akhalsikhe - Zestaponi 70 0.4 0.28

Total 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 Kartli500kV Lines between Zestaponi and Gardabani) will reduce, on average, the 500kV faults which directlyimpact on customer supply from just under 2 faults each year to 1 fault every 2 years i.e. the Imereti linefault 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 toschedule 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 ofmarkets for the energy. The hydro projects currently at the development stage (Oni, Namakhvani andMtkvari cascades) will have the bulk of their energy available during the summer months, the period whenGeorgia already has excess capacity. Therefore they will need access to external markets to be viable forinvestors. This project will have capacity to provide access to the Turkish market for these new hydrogenerators; 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 the2 new connections to Akhalsikhe. The average percent reduction in losses is 0.26%. Assuming a nationalload of 9 TWh and average generation cost of 0.025 / kWh, the avoided cost of generation is 585,000 perannum.

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 theload 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 thesystems specific CO2-emissions are higher than in Georgia. Assuming that the line will be utilised forexport of hydro generated electricity for 6 months out of the year, this could mean a reduction in CO2emissions of 1.1 m tonnes per year.


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


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4 Cost Estimate

(M)

Akhalsikhe 500/400/220kVSubstation including HVDC

500kV Station 10.5

Back-to-Back HVDC 74.5

400kV Station 5.0

Sub Total 90.0

Substation Extensions Gardabani 500kV 1.8

Zestaponi 500kV 5.6

Sub Total 7.4

Overhead Line Construction Gardabani Akhalsikhe 500kV 64.2

Zestaponi Akhalsikhe 500kV 19.0

Akhalsikhe Turkish Border 400kV 4.8

Sub Total 88.0

Cost Estimate without Contingency 185.4

Contingency 27.6Consultant 7.0

Total 220.0Table 4-1: Project Cost Estimate

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


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5 Time Schedule

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

Completion Date

Loan Approval Project Assessment Report 09/08

Agreement on Financing 10/08

Loan Approval 04/09Loan Effective 06/09

Environmental ImpactAssessment

Prepare ToR 09/08

Appoint Consultant 10/09

Deliver Report 04/09

Appoint Project Consultant Prepare ToR 09/08

Appoint Consultant 10/08

Appoint Contractor(s) Issue Specifications andTender Documents

01/09

Tenders Due 04/09

Award Contract 06/09

Transmission Lines Route Survey 09/09

Design and Tower Spotting 10/09

Manufacture 04/10

Foundation Works 09/10

Installation and Stringing 03/11

Commissioning 05/11

Substations Design 10/09

Manufacture 03/11

Delivery 08/11

Erection 10/11

Commissioning 02/12

Converter Station Design 12/09Manufacture 04/11

Erection 03/12

Commissioning 06/12

HVDC Trial Period 09/12Table 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 theconnections to Gardabani and Zestaponi can already contribute to the reliability of the main system inGeorgia 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 isdependant on the completion of the environmental impact assessment (EIA). The effectiveness date isassumed to be 2 months following loan approval; to allow time for loan negotiation. This delay may also bereduced 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 loaneffectiveness is dependent on EIA completion and it is assumed that the main contract(s) will not beawarded until all loans are effective.


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6 Turkish Market Analysis

A detailed analysis of the Turkish Power market and the potential for export from Georgian to Turkey isattached 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 handsand there is a private wholesale market for electricity. Import and export of electricity to Turkey can beundertaken 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 be321-378 TWh, with an annual increase of 12-26 TWh or 6-7.5%. The load profile shows both a winter and asummer 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 theconstruction of nuclear power facilities.Increased load shedding is expected in Turkey in the period to 2012 unless the government is prepared totake 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 inTurkey 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 fallsignificantly or a very substantial expansion of coal fired power generation using domestic lignite issanctioned.Turkish policymakers are very interested in importing electricity from neighbouring countries includingGeorgia. Imports through a 400 kV line to Borchka in Turkey, even if it is fully utilised, would match only2-4% 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 ofthe very low marginal costs of operating HPPs.Turkish policymakers want private sector wholesale traders to import the electricity from Georgia andAzerbaijan 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 fromGeorgia.Georgian hydropower projects will most likely be able to fully utilise the transmission line to Turkey for atleast 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 unlikelydue to Turkeys EU aspirationsCheaper imports from SE Europe it is unlikely that any EU based gas or coal generation could competewith Georgian hydro generationTurkish economic collapse this would only delay the export opportunities but not eliminate them


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7 Georgian Hydro Development

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

Georgia has one of the largest untapped hydro resources in Europe. The technical/economic potential isestimated 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, thermalgeneration 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 ofthe 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

GWhpermonth

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

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


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

Turkey private

wholesale tariff

Georgia balancing tariffESCO

0

1

2

3

4

5

6

7

8

9

10

WholesalepriceEuroc/kWh

Turkey 5 ,45 6,17 5,7 7 6,50 7 ,2 6 6, 82 6,11 6,0 1 7 ,41 7,69 9,09 9,01 8,25 7 ,7 4 8,32 8 ,03 9,33

Georgia 2 ,38 2,52 1,7 2 1,74 0 ,8 9 1, 74 2,85 3,6 4 3 ,72 4,04 3,75 3,85 2,90 1 ,1 9 1,53 1 ,53 1,15

March April May June July AugustSeptem

ber

Octobe

r

Novem

ber

Decem

ber

Januar

y

Februa

ryMarch April May June July

The Georgian economy has been growing rapidly in recent years without a noticeable increase in thedemand for generated electricity. In 2007, when the economy grew by 12.4%, demand for electricitygeneration increased by about 3%. Sluggish electricity demand was largely due to rapid energy efficiencyimprovements in the sector as the transmission and distribution losses have come down significantly. Figure7-3 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 sectorinvestors. 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 UpperRioni river cascade between the Oni and Namakhvani cascade. The total annual generation from these sitesis 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 seasonalpatterns of water flows, would imply that most of the generation takes place in the summer months when theprices 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.a

2007 (actual) 8438

2008 8691

2009 8952

2010 9220

2011 94972012 9782

2013 10075

2014 10378

2015 10689

2016 11010


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The levelised unit costs for new HPPs in Georgia (shown in Figure 7-5 below compared with othertechnologies) 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 andgas-based alternatives, given the high fuel prices prevailing in mid 2008. In the calculations we haveassumed a hydro power facility life time of 30 years. Given the high oil/gas and coal prices prevailing in2008, 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 profitmargin 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


GenerationGWh

permonth

Rehabilitation of existing HPPs

Upper Rioni Cascade

Mtkvari Cascade

Namakhvani Cascade

Oni Cascade

Load growth to 2016 3% p.a.

Thermal production 2007


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

0

10

20

30

40

50

60

70

80

90

Euro/MWhdiscounted

at11,4%

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

Namakhv

ani HPP*Oni HPP*

Mktvari

HPP*

CCGT

200

USD/tcm

Coal 55

USD/t

Wind

onshore

CCGT

400

USD/tcm

NuclearCoal 150

USD/t

Figure 7-6 outlines the approximate electricity available for exports from the four HPP sites in an averageyear, 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 86,2

Namakhvani Cascade 70,0 58,7 73,1 253,3 257,0 226,3 171,4 109,8 135,1 163,7 101,4 23,7

Mtkvari Cascade 29,1 27,2 33,9 138,2 188,7 112,9 58,1 29,8 23,3 27,0 29,3 29,5

Upper Rioni Cascade 85,2 71,4 88,9 308,3 312,8 275,3 208,5 133,7 164,4 199,2 123,4 28,8

Rehabilitation of exisiting HPPs 120,5 127,8 128,6 122,6 149,6 141,0 184,3 179,4 123,7 83,6 108,4 106,1

Export 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 12,2

Load growth to 2016 3% p.a. 240 216 229 205 172 160 172 176 166 176 212 259

Available capacity in the line 730 730 730 730 730 730 730 730 730 730 730 730

Demand 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-) financedthrough revenues from exports to Turkey provided that the Turkish wholesale buyers of electricity are

prepared to pay 5.78.3 Euro c/kWh for Georgian electricity, with a start of delivery in 2013-14. If oil andgas prices remain above 80 USD/bbl in the medium run, it is realistic to assume that such contracts can besecured 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 investmentinto 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 sitesenjoy a significant cost advantage compared with comparable Turkish sites. The cost advantage for the OniHPP compared with a similar site in Turkey could be as high as 2030%, even when accounting for the costof transmitting the electricity from Georgia to Turkey.

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

Given the time it takes to develop the different hydropower projects in Georgia (35 years), it is likely thatGeorgia will only be able to provide significant amounts of electricity for export to Turkey in the period

beyond 2013.


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The prospect of having the access to a transmission outlet to Turkey will be crucial for the development ofthe hydropower potential in Georgia. A potential developer of one of the larger HPP sites in Georgia willmost 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.


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8 Base Case Analysis

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

The Turkish electricity market will be capable of absorbing up to 1,000 MW that can be channelled throughthe 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 suggestthat by 2012 there will be a shortfall of electricity supply from existing, committed and planned generationfacilities 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 theTurkish market could easily absorb additional supplies from or through Georgia, provided that such importsare cost-competitive. If the current prevailing wholesale electricity prices are taken as a benchmark, thenTurkish import demand would be perfectly elastic at about 70 80 Euro/MWh for supplies even in excess ofthe transmission links maximum carrying capacity of 1,000 MW.

The second assumption is based on available evidence suggesting that Georgias 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 ofthe energy could be sold in the Turkish market. Thus, establishing the transmission link with Turkey is anecessary condition for rendering investments in Georgias hydroelectric sites attractive. Internationaltendering of the first sites is scheduled for October 2008, and the Georgian Ministry of Energy and itsadvisors 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 thesites, the first new hydropower plants would come on stream by 2014 - 15. The candidate sites are Oni (272MW), Namakhvani (450 MW), Mtkvari (196 MW) and Upper Rioni (350 MW). The exportable output ofthese 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% ayear. 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 thisforecast, the annual electricity exports to Turkey would rise from 839 GWh in 2013, when the transmissionline is expected to come on stream, to 4102 GWh in 2015, when the new hydropower plants are fullyoperational, 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 loadso 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 Turkeywhenever the line is not fully loaded by Georgian exports and domestic energy flows (i.e., in the periodsJanuary - March and August - December).

The main assumptions concerning the costs of the project are summarized in Table 2, Annex 4. With respectto project finance it is assumed that total basic project costs will be financed with debt, while interest duringconstruction (IDC) would be covered by equity to be raised by the project company. It should beemphasized that since the loan mix and the financing terms have not yet been determined, the figures usedare 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 torecoup the projects costs, including those of the HVDC link with Turkey. Two options are considered:


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A charge based on costs, including depreciation of capitalized project costs, taxes, interest and otherallowable 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 chargewhen the line is poorly utilized. In fact, this problem arises under the base-case scenario since it expects alow loading of the line in the first year of operation. On the other hand, cost-based tariffs have the advantagethat 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 serviceduring the early years; it avoids tariff spikes, but tends to generate a higher return on capital than isnecessary to recover lifetime average costs.

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

The projects weighted average capital costs (WACC) are used to compute levelised unit costs (LUC), i.e.,the projects lifetime average costs (EUR per MWh transmitted). Clearly, if the annual transmission tariff is

based on accounting costs, the projects internal rate of return (IRR) will be close to the WACC. Likewise,the IRR will exceed the projects 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 inthe first operating year.With a cost-based tariff schedule, the IRR is 4.92% and the project would have no cash-flow problem in thefirst year of operation.


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Cost Overrun 20% 30%

WACC 6,28% 6,71%

LUC (EUR/MWh) 6,87 7,71

IRR with frontloaded tariff schedule 7,00% 5,88%Liquidity Problems Yes Yes

Cost-based Average Tariff Revenues (EUR/MWh) 8,80 9,90

Liquidity 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 anunderutilization of the transmission line in the early years of operation

Line congestion due to unexpected increases in domestic load flowsNo development of Georgias 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 theproject 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 of8.80%.

If there were a 30%-increase in basic costs, the LUC would rise to 7.71 EUR/MWh. Moreover, with thefront-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 of9.25 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 transmissioncharges without posing a severe threat to the profitability of hydropower exports.


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Delays in Hydropower Development

As is shown in the above table, a delay in hydropower development of up to 3 years would not jeopardizethe projects 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 regimecould 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 tobridge 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 projects economics in the winter period since in this period thebase-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 theexport 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 developedif 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 powerflows from neighboring countries to Turkey that the transmission link in Georgia could facilitate. Based onits natural gas reserves, Azerbaijan is in the position to build new gas-based power plants with an exportablesurplus of at least 3,500 GWh/year from 2015 onwards. So the potential electricity exports from Azerbaijanto Turkey could almost match the expected hydropower exports from Georgia. Needless to say, whether ornot Azerbaijan will exercise this option is subject to the hard-to-predict future price differentials between theTurkish/Azeri gas and electricity markets (Azerbaijan has the choice between exporting gas or gas-basedelectricity). The same caveat applies to the potential for surplus power exports from Armenia, which willstrongly depend on the availability and cost of gas imports from Iran and/or Russia. In any case, althoughthe potential for regional power trade through the Georgian transmission link is no insurance against the riskof 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-emissionreductions 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 projectsfinancial outlook. Based on a baseline differential of 269 kg of CO2 per MWh exported from Georgia toTurkey (annual average of 1.06 million tons of avoided CO2), and assuming that the price for emissionreductions 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 5,87

IRR with front-loaded tariff 8,27% 7,11% 6,09%Multi-year cash flow problems Yes Yes Yes


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would amount to EUR 70.3 million; at 10 EUR/t, the discounted revenues would be worth EUR 140.6million, equivalent to 64% of the projects 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 wouldimprove the profitability of the project. For instance, with additional 500 GWh/year exported to Turkey, theLUC 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 Turkeymay deviate from the expected value, thus affecting the levelised unit transmission costs (other things beingequal). To illustrate the point it is assumed that the present value of energy exportable to Turkey would benormally 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 LUCis 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


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10 Institutional Arrangements

The institutional arrangements within Georgia for development and operation of the project are still underreview by the Government of Georgia. The preferred arrangement will be communicated during the lendersappraisal 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 ofGeorgia)Power Transit Capability Analysis from Azerbaijan to Turkey by Georgian Centre for TransmissionSystem Planning2 sponsored by USAID/USEAElectric 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 isconsidered 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 wascompleted in December 2007. This study concluded that the project can reasonably be implemented intothe existing MoE EHV network and that Given the ability to secure the requisite load case commitmentscontractually, and a reasonable level of capita cost control, the Project can be viewed as economically andfinancially 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 and15% IRR

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


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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$ Million

Gardabani Akhalsikhe 500kV Overhead Line 93.2

Zestaponi Akhalsikhe 500kV Overhead Line 31.5Akhalsikhe Turkish Border 400kV Overhead Line 17.5

Akhalsikhe 500kV Substation 20.0

Akhalsikhe 400kV Substation 8.5

Akhalsikhe 500/400kV, 600MW, back to back HVDCConverter Station

100.0

Extension of Gardabani 500kV Substation 3.0

Reorganization/ Extension of Zestaponi 500kV Substation 9.0

Contingency 10% 28.3

Total 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 futurecustomers over years in order to have the required return (15% IRR) and thus to be break-even. For eachscenario 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 1B

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


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In this report the Internal Rate of Return (IRR) of a project is assumed to be the discount rate for Net PresentValue of project cash flows equal to zero (NPV = 0) for 100% equity financing. For this reason the Kuljiantariff calculation for Scenario 1B is assumed to be for break-even cash flow i.e. project NPV zero with areduced 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 whichconcluded that:

Overall, there does not appear to be major constraints from environmental impact considerations for thefeasibility 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 detailedEIA study be carried out before work on the project begins. The assessment methodology is stated as beingin accordance with Georgian Ministry of Environment Guidelines (though they do not address methodologyfor EIA) and World Bank/EDRB EIA protocols. Headings considered include:

Physical Impactsland use,

water qualityair qualityflorafaunaSocio-economic Impactstrafficnoise

public 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 environmentalregulations.

1.3 Fichtner Study

1.3.1 General

In November 2007 Fichtner issued a final report Regional Power Transmission Extension Plan forCaucasus Countries (RTEP). This report reviewed 2 new international connections between Georgia andArmenia (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 neighbouringeconomies 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 forinter-regional energy exchangescreating the physical prerequisites and organisational basis for further steps toward a competitive regionalenergy marketcreation of regional energy/electricity hub in Georgia


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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 thegrids. Each option was technically evaluated using weighted multi-criterion analysis considering thefollowing criteria:

Criterion Weighting

Maximum 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 technicalpoint of view. This is due to the significant improvements in reliability of power supply, both for export andinternal 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 Akhalsikhe

New 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%


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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 tariffmust 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 fromGardabani, 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 3

Total Dom Exp Dom Exp

Annualised Project Cost (M) 33.6 21.5 12.1 13.5 20.2

TWh 1.685 0.87 0.815 0.87 0.815

LUC ( 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 andtherefore the study suggests tariff increases to 2.15 cents for domestic energy and 3.44 cents for export tomake 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 reductionand trading benefits. For outage and loss reduction the study calculated the following benefits:

Cost per kWh M per annum

Avoided Outages 0.4 5.9

Loss 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 EnergyBalance 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:


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Case 1 Case 2 Case 3

Export Tariff (/kWh) 0.0563 0.048 0.0563

Export Energy (TWh) 0.815 0.815 0.556

Annual Benefit (M / annum) 29.6 20.2 20.2

Project Cost Allocation (M / annum) 20.2 20.2 20.2

Trading Profit (M / annum) 9.4 0.0 0.0Table 1-6: Fichtner Trading Benefits

The results show that the minimum tariff required at the Turkish border to pay for the export component ofthe project is 4.8 EUR cents per kWh while the minimum export at 5.63 EUR cents per kWh (for the same

break-even) is 0.556 TWh.

1.4 ECON Study

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

Russia: While it may have seasonal needs in the region, its medium/long term goal is to export to Turkeyand other countries. Therefore it is not regarded as a serious export market for Georgian hydro. However, ifRussia 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 pricesand plans for a replacement nuclear plant. As in the Russian case though, this overcapacity could beexported to Turkey via Georgia.Iran: Potentially a summer market for Georgian power transmitted through Armenia in the medium to longterm. 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 toincreased (and more realistic) tariffs and improved metering leading to increased collections. It is thereforeexpected 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 theopportunity 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 thesystem struggles to meet the demand. Wholesale prices were average 11.6 USc/kWh in April 2008. Thewholesale price is expected to remain high unless gas/oil prices reduce significantly and/or a substantialexpansion of lignite plants is approved. Turkish authorities have expressed interest in a connection toGeorgia (to add to new EHV connections under construction to Bulgaria/UCTE). Contracts could benegotiated with the state entity Tetas or private wholesale companies operating in the sector.

1.5 Comments

The Kuljian and Fichtner studies considered only Georgias export potential in their load flows and financialassessments. 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 Georgiansystem.

From a technical point of view Kuljian considered only one technical solution, whereas Fichtner consideredand evaluated various technical solutions for Georgias connection to Turkey at Akhalsikhe. The result ofthe Fichtner analysis (the optimum solution) is Option 5 which is the current project plus an additionalconnection 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 beprovided by Khudoni.


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

Kuljian Fichtner Comment

Interest Rate 6.4% 6.4%

Depreciation 12 Years 30 Years

Discount Rate 9% 8%

Link EnergyTransfer

4.6 1.358 TWh See note below

Load Factor 74% 65% Kuljian notexplicitly 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 thelink 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 months

Availability = 95%

Then annual energy transmitted = 4.6 TWh

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

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

Both Fichtner and Kuljian calculated the Levelised Unit Cost (LUC) required to deliver a stated return onthe investment for the shareholder using internal rate of return (IRR). The results are summarised in Table3-8.


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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) - 188 212 212

Total Finance (M) 242 268 308 308

Fees ( M) - 26 5 5

IRR 15% * 7.8% 7.8% *This value isnot clear seenote in 3.2.4above

TWh 4.6** 4.6** 1.685 2.228 **Kuljian notexplicitly 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 = AnnualIncome / TotalFinance

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. Highertariffs 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 reviewcurrent and projected supply and demand for electricity, as well as the expected prices in the wholesaleelectricity market.


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2.1 Sector OrganizationThe Turkish electricity sector is in large part deregulated. In 2001, the government enacted the ElectricityMarket 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 petroleummarkets, including issuing licenses, setting tariffs and ensuring competition by eliminating verticallyintegrated state monopolies and allowing participation of the private sector in Turkeys energy sector. TheMinistry of Energy and Natural Resources is responsible for overall policy in the sector.Figure 2.1: Structure of Turkish Electricity Sector


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The Turkish electricity sector is currently in a stage of transition towards a fully deregulated market. EUASstill own approximately 40% of the generation capacity in Turkey. As part of the deregulation plans for thesector, it is envisaged that no private sector company will control more than 20% of total generationcapacity3. EUASs 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 isregulated 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 forhourly generation capacity for the following day. The EUASs regulated cost and the hourly competitively

tendered privately provided electricity is averaged and makes up the electricity price that TEIAS uses for onsale to TEDAS and the private distribution company. The wholesale market for electricity is expected to befully deregulated by 2012, although the date for full deregulation has been extended several times in recentyears.Much of the electricity generation takes place in the Eastern part of the country while the consumption is inthe West and South. Transmission of electricity in Turkey is controlled by TEIAS. The transmission grid inTurkey is extensive and has low losses (around 3%), despite long transmission lines. It is possible for privatesector 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 thatbuilds 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 distributionregion in Turkey. The tender for the privatisation of state-owned distribution companies is expected to takeplace before 2010.Companies with an annual consumption in excess of 3 GWh are allowed to freely choose their supplier ofelectricity.

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 hasbeen particularly rapid in recent years partly due to a booming economy but also because of a significanterosion 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 andlow forecast estimating that the demand will increase by 67.5% 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 ,8 378,2

Demand scenario 2 TWh 196,7 209,1 222,3 236,3 251 ,1 267 ,0 283,8 301 ,9 321,6

Demand growth scenario 1 TWh 15,4 16,9 18,3 19,8 21,2 22,4 23,9 25,5 26,4

Demand 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 137190 TWh in the decade to 2016doubling the need for generation capacity in Turkey. The demand growth in 2016 alone is estimated to 1926 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 prolongedslowdown in economic growth would have the same effect. The economic crisis in 2001 saw a fall in theelectricity consumption in Turkey. More effective management of the distribution sector, which currentlyexperiences technical/commercial losses of approximately 17%, compared with 57% in many EUcountries, may also reduce demand for generated electricity.But the trend, over the last five decades, of steadily increasing demand is likely to continue. The averageTurkish citizen consumes only one third as much electricity as the average EU citizen and demand isexpected to grow as GDP per capital catches up with the EU countries.

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


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2.3 Generation MixTurkey has limited domestic energy resources and has become increasingly dependent on imports to fuel itsrapidly 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 thegeneration expansion from 1990 onwards has come through a rapid growth in gas-based generation usingimported 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.


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Figure 2.1: Fuel Mix Development in Electricity Generation, 19702005

2 Source: International Energy Agency

TEIAS has also made projections for the energy mix for electricity generation in Turkey to 2016. Theprojections include existing generation, projects under construction and projects that have receivedgovernment approval for development.

As can be observed in figure 2.3, the Turkish electricity market is experiencing an increasing mismatch assupply has struggled to keep up with surging demand. The situation is expected to deteriorate further in thecoming years, resulting in increased load shedding.

Figure 2.3: Demand and Fuel Mix Development, 20062016

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

AnnualgenerationTW

hinTurkey

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 theTurkish private wholesale electricity market heavily to a sharp increase in oil and gas prices. The averagegas price in Turkey in 2008 is expected to be 223 Euro/tcm, giving a generation cost from gas fired powerstations of 59 Euro c/kWh depending on the thermal efficiency of the plants (2956%). Given the growingsecurity of supply concerns that increased gas based generation creates among Turkish policymakers and thesignificant importation of inflation through the increasing price for gas, the government in Turkey isinterested 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


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Hydropower Planning Agency (DSI) auctioned, to the private sector, the rights to develop a total of morethan 7,500 MW of new hydro capacity with expected annual generation in excess of 27 TWh. Since not allof the sites will be developed, TEIAS estimates total hydropower generation in Turkey to be 67 TWh in2013. Turkey will then have utilized the most economically feasible half of its potential. It is also worthnoting that because of climate change, generation of electricity from existing HPPs in Turkey is expected todecline 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 sectorcompanies bid on the highest water usage tax they are willing to pay to DSI per kWh generated. The DSI taxfluctuates 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 240MW Cizre Baraji HPP site in January 2008 which attracted a bid of 3.7 Euro c/kWh from Aydnl Enerji -the winning company. Econ estimates that this project needs a levelized tariff of at least 6.7 Euro c/kWh tooffer a reasonable return for investors. The 19 MW Catak HPP in the Rize region in Turkey fetched an alltime high DSI tax charge of approximately 4,1 Euro c/kWh in a tender in May 2008. The DSI tax isexpected 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 thecost of generating electricity from HPPs and the long run marginal cost in the electricity system, throughheavy taxation of HPP plants.

4 See Europes hydropower potential today and in the future: Bernhard Lehner etc 2001


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Table 2.2: DSI Tax Charge Greenfield HPP Developments, 20062008Project name Installed capacity MW Annual production GWh Load factor % DSI tax Euro c/kWh

Cizre Baraj ve HPP 240 1 208 57,5 % 3,68

Dereky-Demirkap HPP 105 366 39,8 % 3,43

amlca HPP 110 376 39,0 % 3,37Alara Enerji Grubu HPP 187 622 37,9 % 3,06

Narl HPP 130 402 35,3 % 2,78

Kayraktepe HPP 290 768 30,2 % 2,50Aksu-Anakol HPP 120 344 32,7 % 2,49

Kavakbendi HPP 140 652 53,2 % 2,34

etin Bar. Ve HPP 350 1 237 40,3 % 1,91

Arkun HPP 222 790 40,6 % 1,68

Silvan Baraj ve HPP 160 681 48,6 % 1,36

Silopi Enerji Grubu HPP 140 356 29,1 % 0,82Alkumru Bar.HPP 222 812 41,8 % 0,55

Sami Soydam Bar.HPP 175 515 33,6 % 0,42

Ayval (oruh) HPP 125 409 37,4 % 0,28

Kemah Bar ve HPP 135 494 41,8 % 0,04

Dilekta Bar.HPP 125 328 30,0 % 0,04Karakurt HPP 110 342 35,5 % 0,02

Average 171 595 39,1 % 1,71

Source: Econ calculations based on information from DSI using a Turkish Lira/Euro exchange rate of 0.5431

Due to the rapid increase in the price of oil and gas, coal generation based on domestic lignite and importedhard coal has become more attractive. But with the prices of Australian hard coal, following the prices of oiland gas upwards and approaching 100 Euro/tonne in June 2008, an increase of 50% from 20075, generationcost of new coal fired generation based on imported coal is approaching 6-8 Euro c/kWh. As a rule ofthumb, 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 carbonemissions. Turkey has reserves of at least 8.1 bn. tonne of mostly low quality lignite. 80% of remainingreserves have a calorific value of less than 2,500 kcal/kg6. Using domestically produced lignite for powergeneration will mitigate the increasing security of energy supply concerns for Turkish policymakers andlower the cost of generating electricity.The Turkish government intends to expand lignite production significantly in the coming years. A total of5,000 MW of new domestic lignite generation capacity is planned. This could produce as much as 38 TWhof electricity annually, an increase of approximately 20%7. In order for lignite to substitute for gas basedgeneration in any meaningful way, Turkey needs to build at least 10,000 MW in new capacity by 2016 inaddition 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 expansioncould be seen as a last resort option for an energy system squeezed between rapidly rising energy costs andgrowing 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 ofimported coal and gas and the cost advantage of domestically produced lignite is uncertain in the mediumand long run.In addition to hydro and domestic coal, the government in Turkey intends to rely on nuclear energy to meetthe future energy demand. A tender was published in the spring of 2008 to construct a 3,0005,000 MWnuclear power plant9 with several other power plants at the planning stage. A 4,000 MW nuclear power plantcould produce as much as 30 TWh annually. However, it may take as much as 10 years from tender close tothe nuclear power plant can be commissioned and the cost of nuclear energy may be approximately 5-7 Euroc/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 oftapping domestic hydro resources to meet peak demand, and expanding domestic lignite and nuclear

5Please see Global Coal RB index for details www.globalcoal.com

6 Please see Resources, quality and economic importance of solid fossil fuels in Turkey 2004http://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 inTurkey in email correspondence with Econ 17/6 2008.9 See http://www.tetas.gov.tr/nukleer/eng/nklr.htm for details.


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production to meet base load demand. Additional natural gas generation may also be expected if gas pricesreduce 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 forsignificant imports of electricity to Turkey.The import of electricity on the proposed link from Georgia would constitute 13% of the total electricityconsumed in Turkey in 2013 and would therefore not be expected to have a material impact on prices inTurkey.Figure 2.4 below represents a best-case schedule for new lignite and nuclear electricity generation capacityin 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.


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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 aresult 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 Januaryand February 2008 where prices on average remained above 6.7 Euro c/kWh throughout the day, the pricesdipped during the night time (1 AM to 7 AM) and remained high for the rest of the day. Prices in this periodare largely set by gas based generation and have been in the range of 7-9 Euro c/kWh in 2008. In the lowload period during the night, the prices are set by base load domestic lignite electricity generation and the

prices fall to 2.74.7 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


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Figure 2.5 Private Wholesale Electricity Prices March 2007July 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.07

mai

.07

jun.07

jul.0

7

aug.07

sep.07

okt.07

nov.07

des.07

jan.08

feb.

08

mar

.08

apr.0

8

mai

.08

jun.08

jul.0

8

Averageprivatewholesaleprices

inTurkeyE

uroc/kWh

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 countryimported 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 to17 TWh annually. This interconnection capacity may have an impact on the development of the electricity

prices in Turkey although Turkeys neighboring countries in the EU are facing the same input prices togenerate electricity as Turkey.10.Import and export of electricity to Turkey is liberalized. Both TETAS, the state owned wholesale tradinglicense 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, statedthat 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 includingGeorgia.Mr. Haci Duran Gokkaya, the General Manager in TETAS seemed more interested in entering into longterm power purchase contracts in discussions with Econ during the same visit, but as TETAS will take theirinstructions 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 withheadquarters 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 costapproximately 5 bn. Euro or approximately 0,33 Euro/kWh generated (Financial Times 23 June 2008)


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Name of company Annual turnover Contact details

Enerjisa Elektrik (fullyowned 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 aswholesale 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 privatewholesale traders.EMRA has issued regulations for import and export of electricity to Turkey12. The regulations specify theconditions that need to be fulfilled in order for an entity to engage in import/export of electricity. Thecriteria 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 theimporting 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 ofelectricity that will be imported.Applications for import/export of electricity will be reviewed by the Ministry of Energy and NaturalResources, and the opinion will be taken from TEIAS regarding the transmission capacity on the Turkishside of the border. If the opinion is positive, the application will be posted on the website to the Ministry ofEnergy and Natural Resources.In an interview with Econ in Ankara in May 2008, Mr. Kemal Yildir, Assistant General Manager in TEIASconfirmed 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 transmissioncapacity from Borchka to Central and Western Turkey.TEIAS will undertake a competitive tender to price the usage of the capacity if there are more companiesthat 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 fromthe Ministry of Energy in Georgia. In other words, the Georgian Ministry of Energy can to a large extentdetermine the electricity tariff for export of electricity to Borchka from the Georgian grid. If the Ministry ofEnergy in Georgia does not approve export of more than 1000 MW (the assumed capacity in the line) therewill be no tender on the Turkish side and therefore a regulated transmission tariff.2.6 Feasibility of Electricity Imports from GeorgiaTurkey is expected to experience significant shortages in its power sector in the medium term. The Ministryof Energy and Minerals in Turkey indicated a strong interest in imports of electricity from neighboringcountries, 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 onlyjustify one 400/500 kV line from Georgia to Turkey in the short/medium run without expanding thetransmission 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 aslong 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 tradersfor 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 termPPAs 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


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Because of the very heavy taxation on new HPP sites for development (up to 3,7 Euro c/kWh in DSI waterusage tax alone), the most prospective large scale Georgian HPP sites have a significant cost advantagecompared 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 isestimated to up to 60 TWh of which approximately 8 TWh, or less than 15% of the potential, has beendeveloped. But the country has struggled to attract private sector capital to develop the resources. There areseveral reasons for this, but the principal reason is that the tariff levels in Georgia and neighbouring

countries, that are connected with Georgia with significant transmission capacity, (Azerbaijan, Russia), havebeen 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 anddistribution companies. An independent regulatory authority supervises the sector and is responsible fortariff 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


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imports meet peak and winter demand. Georgia was a net exporter of electricity in 2007, mainly due toexports in the summer time.An Energy System Commercial Operator (ESCO) is responsible for the balancing market for contracting forelectricity 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 Georgiawith the Russian transmission network. The line is jointly owned by RAO UES (50%) and the Georgianstate (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, ownssome 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 distributionoutside Tbilisi and fully owned by Energo Pro). Kakheti Distribution Company is a smaller distributioncompany, operating in the east of the country. There is also a state-owned distribution company inAbkhazia, outside the control of the central Government in Tbilisi.


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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. Inaddition, 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 generation17% and imports approximately 5%. Approximately 8% of the generated electricity was exported, primarilyin 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


GWhpermonth

Source: ESCO

Georgia exported approximately 625 GWh of electricity in 2007 according to ESCO, much of it on swapcontracts 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 theaverage 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