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Russian power utilitiesUncertainty means opportunityJune 25, 2008

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Utilities

Initiation

Sector report

June 25, 2008

Russian power utilities: Uncertainty means opportunity

Over the last several months, the stock performance of utility companies has been heavily

impacted by acquisition activity and the restructuring of UES. Once these factors have been played

out (which, for most stocks, we expect by autumn), the companies’ underlying fundamentals

should become the main driver of their share price performance.

Just a week before UES will cease to exist, the future earning potential of utility companies is

hardly more certain than it was when the reform began back in 2001. The government has yet to

decide on key issues that will determine cash flow to shareholders: namely, the capacity market for

generation companies, and the parameters of regulatory asset base (RAB) regulation for grid

companies.

These crucial decisions essentially involve political will. The state is facing a trade-off between

keeping electricity tariffs low, which would help restrain inflation, and switching to market-based

pricing methods, which would imply a rise in the effective electricity price paid by consumers. The

latter would create stimulus for investment, power saving, and improved efficiency at utility

companies.

While the government is likely to create all the conditions necessary to attract new investments,

existing assets face the highest regulatory risk in our view. In the generation segment the major

risk is discrimination between old and new generators; in the grid segment, the major risk is the

initial value of the regulatory asset base, which is to be determined by the regulator.

We expect the generation segment’s revenues to be fully liberalised by 2014 and RAB regulation

to be completely introduced in the distribution and transmission segments by 2011 and 2012,

respectively. Our assumptions imply an 18.8% CAGR in 2008-2014 of the total price received by

generators, and an average tariff CAGR through the RAB introduction date of 14.9% in both the

distribution and transmission segments.

Under these assumptions we are initiating coverage on 51 currently listed utility stocks with 36

BUY, 6 HOLD, and 9 REDUCE recommendations.

Upside is distributed unevenly across the companies, with a 58% average for generation

companies and a 38% average for distribution companies. At current OTC forward prices, we see

a modest upside of 10% for the Federal Grid Company (FSK).

We expect the following events to become potential triggers for utility stocks through the end of this

year:

Announcement of capacity market rules for generation companies

Announcement of RAB regulation parameters for several pilot distribution companies

TOP PICKS

Ticker

Market

price,

Jun 19 12m TP Upside

Generation

OGKB RU 0.088 0.172 95%

OGKD RU 0.080 0.166 108%

OGKE RU 0.128 0.209 64%

MSNG RU 0.177 0.278 57%

TGKE RU 0.00078 0.00165 112%

TGKG RU 0.090 0.168 87%

TGKK RU 0.00112 0.00215 92%

KZBE RU 0.0235 0.0490 109%

TGKM RU 0.0083 0.0198 140%

KRSG RU 4.0 10.1 153%

Distribution

MRKC RU 0.0519 0.0840 62%

MRKK RU 11.5 28.1 145%

MRKP RU 0.0141 0.0226 61%

MRKS RU 0.0183 0.0291 59%

MRKV RU 0.0073 0.0191 162%

MRKZ RU 0.0111 0.0218 96%

Integrated

BEGY RU 1.59 4.04 155%

IRGZ RU 0.88 2.14 143%

NVNG RU 71 159 125%

CONTACT

Ilya Koupreyev

[email protected]

+7 495 545 0535

Dmitry Astakhov

[email protected]

+7 495 545 0535

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CJSC Glitnir Securities l Paveletskaya Pl. 2, bld. 3 l Moscow 115054 l Russia 2/183

Table of contents

Executive summary ....................................................................................... 4

Target prices and investment recommendations ....................................... 9

Overview: Russian utilities at a glance ..................................................... 16

Lack of capacity: Main driver behind the reform ...................................... 18

The reform .................................................................................................... 21

Restructuring .......................................................................................................................... 21

Formation of target sector structure ........................................................................................ 23

UES breakup .......................................................................................................................... 31

Privatisation ........................................................................................................................... 36

The switch to market-based pricing ........................................................................................ 41 Generation: The road to the free market ............................................................................ 43

Distribution: The switch to RAB .......................................................................................... 51

Fuel supply ................................................................................................... 54

Valuation ....................................................................................................... 58

Macro assumptions ................................................................................................................ 58

Generation companies ........................................................................................................... 60 Power consumption ........................................................................................................... 60

Production.......................................................................................................................... 62

Electricity prices ................................................................................................................. 64

Heat revenues ................................................................................................................... 70

Costs ................................................................................................................................. 71

Capex ................................................................................................................................ 73

Taxation of hydroelectric plants .......................................................................................... 74

Discount rate and terminal growth ...................................................................................... 74

Valuation results ................................................................................................................ 75

Sensitivity analysis ............................................................................................................. 79

Distribution companies ........................................................................................................... 81 Depreciated replacement cost (DRC) estimate................................................................... 81

Capex ................................................................................................................................ 84

Discount rate ...................................................................................................................... 85


What do our valuation assumptions imply by 2011? ........................................................... 88


Foreign peer comparison ................................................................................................... 90

Transmission companies ........................................................................................................ 92 Depreciated replacement cost (DRC) estimate................................................................... 92

Capex ................................................................................................................................ 92

Discount rate ...................................................................................................................... 93


What do our valuation assumptions imply by 2012? ........................................................... 94


Foreign peer comparison ................................................................................................... 95

Independent AO-energos ....................................................................................................... 97

Far East Energy Company ..................................................................................................... 97

UES ....................................................................................................................................... 98

MRSK Holding ..................................................................................................................... 100

Far East Energy Holding ...................................................................................................... 100

InterRAO .............................................................................................................................. 101


Appendix 1: Company-specific issues ................................................... 102

Appendix 2: Selected financials, distribution companies .................... 104

Appendix 3: Company profiles ................................................................ 105

OGK-1 .................................................................................................................................. 106

OGK-2 .................................................................................................................................. 109

OGK-3 .................................................................................................................................. 112

OGK-4 .................................................................................................................................. 115

OGK-5 .................................................................................................................................. 118

OGK-6 .................................................................................................................................. 121

TGK-1 .................................................................................................................................. 124

TGK-2 .................................................................................................................................. 127

Mosenergo (TGK-3) ............................................................................................................. 130

TGK-4 .................................................................................................................................. 133

TGK-5 .................................................................................................................................. 136

TGK-6 .................................................................................................................................. 139

TGK-7 .................................................................................................................................. 142

TGK-8 .................................................................................................................................. 145

TGK-9 .................................................................................................................................. 148

TGK-10 ................................................................................................................................ 151

TGK-11 ................................................................................................................................ 154

Kuzbassenergo (TGK-12) .................................................................................................... 157

TGK-13 ................................................................................................................................ 160

TGK-14 ................................................................................................................................ 163

Bashkirenergo ...................................................................................................................... 166

Irkutskenergo ....................................................................................................................... 168

Novosibirskenergo ............................................................................................................... 170

RusHydro ............................................................................................................................. 172

Krasnoyarsk GES ................................................................................................................. 175

Appendix 4: List of figures....................................................................... 177

Disclosures ................................................................................................. 181

Disclaimer ................................................................................................... 182

Contact Information ................................................................................... 183


Executive summary

The reform

Historically, the utilities sector was heavily dependent on the state. This is because almost the

entire sector was controlled by state-owned corporations, and revenues were completely

regulated by the government.

The need to construct new capacities and modernize old power plants has forced the

government to implement a thorough reform of the sector. The reform started in 2001 and

focused on three types of tasks: restructuring, privatisation, and the switch to market-based

pricing.

Restructuring

The restructuring process involves the separation of potentially competitive companies

(generation and supply) from natural monopolies (distribution and transmission grids).

Restructuring is nearly complete: 72 vertically-integrated companies have been broken up and

regrouped into new entities that operate in separate segments: 21 generation companies, 11

interregional distribution companies, and one transmission company (the Federal Grid Company,

or FSK). The restructuring process will be completed on July 1, 2008. On this date, UES, the

largest utility company in Russia, will cease to exist.

Privatisation

According to the reform, thermal generation companies are to be privatised. The privatisation

option remains open for distribution grids; however, hydroelectric and nuclear power plants as

well as the transmission grid are to remain under state control for the foreseeable future.

Generation companies are privatised in two ways:

1. Through additional share issues and the sale of state-attributed stakes (stakes in

generation companies that are owned by UES and correspond to the state’s interest in

UES). To date, 19 of the 20 thermal generation companies have completed additional

share issues or have had a state-attributed stake in them sold by UES. The remaining

company, OGK-1, is expected to be privatised by the end of 2008.

2. Through the UES breakup, during which UES’s three largest minority

shareholders Gazprom, Norilsk Nickel, and SUEK will receive stakes in selected

generation companies

To date, 44% of the Russian generation sector has been privatised.

Market liberalisation

The outdated cost-based tariff regulation system is to be replaced with market-based

mechanisms that would encourage investments in the sector. These principles involve the

creation of free markets for the potentially competitive segments: generation (wholesale market)

and supply (retail market). For naturally monopolistic segments distribution and transmission

grids tariff regulation is to be switched to an asset-based method such as the regulatory asset

base (RAB) method, which would provide shareholders with market return on invested capital.

Generation

Currently, compensation for generators is composed of two parts: electricity price and capacity

payment. The system is designed in such a way that the electricity price covers the generators’

variable costs (mainly fuel costs) while the capacity payment covers fixed costs and the cost of

capital. Theoretically this system implies that nearly 100% of generators’ free cash flow depends

solely on capacity payments.

The reform envisages the creation of free markets for both electricity and capacity. To date,

however, the government has made decisions regarding the liberalisation of the electricity market

only. The New Wholesale Market of Electricity and Capacity (NOREM) was launched in

September 2006. According to the schedule approved by the government, the portion of

electricity produced by existing generators that is sold at free prices will gradually increase from

0% in 2006 to 100% in 2011 (on July 1, 2008, this share will reach 25%).

The capacity market is to be liberalised at the same pace as the electricity market. However, the

government is still discussing the rules for the capacity market, and 100% of capacity payments

(the most important source of earnings for generators) is still regulated. Given that in the current

market model, capacity payments determine the free cash flow of generators, the fundamental

value of generation companies is still fully dependent on the state’s will.


Heat revenues, which make up to 62% of the top line for territorial generation companies (TGKs),

are not affected by the reform of the electricity sector. However, the government may start to

make changes in heat segment regulation similar to those it has made in electricity generation.

Grid segment

On June 18, 2008, the government signed Decree No. 459, which sets the general framework for

the introduction of the regulatory asset base (RAB) tariff-setting approach in the grid segment.

The RAB approach implies that shareholders earn a market-based return on invested capital; it

also has imbedded mechanisms to encourage cost-cuts and improvements in operational

efficiency.

Prime Minister Vladimir Putin recently announced that the transition to the RAB method is

expected to be made for several pilot distribution companies beginning July 1, 2008, and will be

completed for all distribution companies by 2011. The government has not yet announced the

parameters of the RAB method, such as an appraisal of the distribution companies’ assets and

regulatory WACC.

There have been no official announcements regarding the introduction of the RAB method for

transmission companies, but it seems logical they will undergo changes similar to those in the

distribution segment.

Our view and valuation

The short-term stock performance of wholesale generation companies (OGKs), TGKs, and UES

is impacted by temporary and technical factors, including the sale of UES’s generation assets to

strategic investors and the UES breakup. We expect these factors to disappear by autumn of this

year; afterwards we expect investors to shift their focus to cash flow and the fundamental value

of assets.

We used the DCF method to value generation companies, and an assets-based approach to

value distribution and transmission grids. We valued vertically integrated independent energy

companies as the sum of the parts of their respective generation and grid assets.

Generation segment

Supply and demand of electricity

We forecast electricity consumption would advance at a CAGR of 2.7% through 2020, which is

one-third below the government’s forecast of 4.1%. The government’s estimates seem overly

aggressive to us, as over the last 10 years (which have been characterized by strong GDP

growth), electricity consumption has shown an annual growth rate above 4.1% only once.

Furthermore, the Russian economy is one of the most energy intensive in the world, and we feel

it has unrealized energy-saving potential.

Figure 1: Power consumption, government forecast vs. Glitnir

Source: Ministry for Industry and Energy, Glitnir estimates

Unfortunately, the government’s plans for construction of new capacity are directly related to its

forecast of electricity consumption. The government has developed a general scheme for

allocating power facilities up to 2020, which envisages a 65% increase of installed capacity.

Based on this scheme, UES has required that the new owners of OGKs and TGKs sign special

capacity-delivery contracts obliging them to fulfil their respective investment programs. We

expect that commissions of new capacity will outpace growth of electricity demand in the near

term; this would put pressure on existing generators’ load factors within two to seven years.

600

800

1 000

1 200

1 400

1 600

1 800

2 000

TW

h

Government base scenario Glitnir forecast

CAGR base 5.2%

CAGR base 3.6%

CAGR base 3.7%

CAGRGlitnir 3.4%

CAGR Glitnir 2.4%

CAGR Glitnir 2.5%


We believe the generators will finish projects that have already been started, but projects that

have not been started are likely be amended or even cancelled if the observed electricity

demand falls short of the government’s forecast. Under our growth assumptions for electricity

demand, we expect commissions of new power plants to virtually stop in 2014-2016 and existing

generators’ load factors to recover by 2017-2018.

Figure 2: Load factors, generation companies

European Russia Siberia

Source: Company data, Glitnir estimates Source: Company data, Glitnir estimates

Electricity tariffs

We modelled electricity prices and capacity payments separately for each generator. Our

assumptions are as follows:

1. The amount of electricity sold at free prices will expand in line with the government-

approved schedule (i.e. it will reach 100% by 2011).

2. The capacity market will start to function in 2009. The amount of capacity sold at

market prices will increase according to the same schedule established by the

government for the electricity market (i.e. 30% starting January 1, 2009, to reach 100%

in 2011).

3. Free electricity prices will move towards levels that correspond to the fuel cost of a

new entrant.

4. Free capacity payments will move towards levels that correspond to the sum of the

fixed cost and cost of capital of a new entrant.

5. In European Russia, a new entrant is a gas power plant (assumed construction cost of

USD 1 060/kW). In Siberia, a new entrant is a coal power plant (assumed construction

cost of USD 1 380/kW).

However, we estimate there is a gap between the current average regulated capacity payment

and the theoretical market-based capacity payment (related to a new entrant’s costs) of 3.2x for

European Russia and 6.7x for Siberia. This means that, assuming 30% of capacity is sold at free

prices in 2009, an immediate unrestricted switch to market-based pricing for capacity would drive

the effective total price received by generators up 60% in European Russia and up 122% in

Siberia in one year. We believe the state would find such a sharp hike unacceptable, and

therefore we expect it to put a temporary price cap on free capacity payments for existing

generators in order to ease the transition to unregulated prices. We expect that the market-based

capacity payment for existing generators will be discounted 65-70% in 2009 relative to new

generators, and that this discount will gradually be reduced to 0% by 2014, which would signify

the complete liberalisation of the generation segment’s revenues.

Overall, our assumptions on the electricity and capacity markets imply a total effective electricity-

price CAGR of 17.7% in European Russia and 26.1% in Siberia in 2009-2014.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Hydro existing Nuclear existing

CHP existing GRES existing

New generation

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Hydro existing CHP existing

GRES existing New generation


Figure 3: Effective electricity prices



Heat regulation

For valuation purposes we assumed the heat segment would remain under state regulation for

the foreseeable future; however we expect the operating profitability of the heat segment will

gradually expand from an average of 8.4% in 2006 to 13.0% in 2011. The probability of

deregulation of the heat market or the switch to a regulatory approach that allows for adequate

return on invested capital creates upside risks to our valuation.

Taxation of hydroelectric power plants

We expect the government will extract the huge profits that otherwise would be earned by

hydroelectric generators in the liberalised market through taxation. For valuation purposes we

assumed hydro assets would be taxed at a corporate profit tax rate of 60% in 2012 (vs. the

normal rate of 24%).

Cost of equity

Due to the high degree of uncertainty regarding the future rules of the capacity market and the

probability of government intervention, we consider generation a risky industry. We estimate the

cost of equity of generation companies at 13.4-16.9% (10.9% market risk + company-risk

premium), depending on corporate governance and liquidity risks specific to each company.

We applied a RROE of 12.4-13.9% in the valuation of distribution companies, and 12.4% for FSK

Valuation results

Our per-kilowatt valuation of generation companies implies the following relationships (based on

averages for respective asset groups):

1. OGKs’ coal-fired power plants (USD 760/kW) have a 10% premium over gas-fired

power plants (USD 689/kW), mainly because gas prices are expected to outperform

coal prices going forward.

2. OGKs’ power plants located in Siberia (USD 705/kW) have a 12% premium over those

in European Russia (USD 627/kW), mainly because of the difference in new entrants’

construction costs between those regions.

3. RusHydro (USD 1 038/kW) has a 64% premium over OGKs (USD 633/kW) as

hydroelectric power plants receive the same electricity prices as thermal plants but

bear no fuel costs.

4. TGKs (USD 771/kW) have a 22% premium over OGKs (USD 633/kW), as they

produce significant volumes of heat in addition to electricity, while OGKs have

relatively small heat capacities.

Distribution and transmission grids

We expect the RAB model will be implemented by 2011 for all distribution companies, and by

2012 for FSK.

0

20

40

60

80

100

120

US

D/M

Wh

Average effective capacity payment

Average effective electricity price

0

10

20

30

40

50

60

70

80

90

100

US

D/M

Wh




A key issue determining the fair value of grids is the initial valuation of existing assets for tariff-

setting purposes: the ―initial RAB.‖ We based our valuation on an independent appraiser’s

estimates of grid-replacement cost and cross-checked these estimates against foreign peers for

validity. To get the current fair value of grid assets, we estimated the RAB for each company as

of the RAB introduction date (we assumed it would equal the company’s fair enterprise value as

of that date) and discounted it back to the present. We did not include in the RAB assets

financed by connection fees, which is in line the government’s recently approved Decree No.

459; therefore this source of short-term profit appears to have virtually no impact on the fair

values of electricity grid companies.

The state and UES are going to pump about USD 18.3 bn into the charter capital of FSK in a

series of additional share issues; the bulk of this is cash proceeds from the sale of state-

attributed stakes in generation companies. These funds will be spent on FSK’s massive capex

program. However, as the current regulatory framework does not provide FSK shareholders with

an adequate return on invested capital, we believe the capex presents significant value-erosion

risks. We estimate FSK’s target price could have been 26% higher if the company had not made

any capital expenditures until switching to the RAB model.

Independent energy companies

Investors should take into account that independent energy companies own distribution and

transmission grids in addition to power plants. We estimate grids add some USD 76-227/kW to

the value of the generation assets controlled by independent energy companies.


Target prices and investment recommendations

Figure 4: Valuation summary, Russian generation

Source: RTS, Glitnir estimates

2008e 2009e 2010e 2008e 2009e 2010e

Cur-

rent

Tar-

get

Cur-

rent

Tar-

get

Russian thermal generation companies

OGK-1 Russia OGKA RU common Buy USD 0.115 0.132 0.0903 46% 4 029 4 228 18.0 8.8 3.9 39.8 16.2 5.9 444 631 84 120

OGK-2 Russia OGKB RU common Buy USD 0.149 0.172 0.0880 95% 2 880 2 488 44.8 9.7 4.9 neg 28.5 11.1 286 582 52 105

OGK-3 Russia OGKC RU common Buy USD 0.141 0.161 0.116 39% 5 520 2 386 13.5 9.8 9.7 27.5 24.0 27.1 281 471 74 125

OGK-4 Russia OGKD RU common Buy USD 0.146 0.166 0.080 108% 5 041 3 593 20.5 7.0 2.9 89.3 18.4 6.2 416 1 005 66 160

OGK-5 Russia OGKE RU common Buy USD 0.186 0.209 0.128 64% 4 528 4 409 20.0 11.6 6.5 67.9 26.6 11.5 509 826 115 187

OGK-6 Russia OGKF RU common Buy USD 0.0885 0.102 0.078 30% 2 516 2 071 49.8 26.3 13.5 neg neg neg 229 300 60 79

TGK-1 Russia TGKA RU common Hold USD 0.00132 0.00151 0.00134 13% 5 141 4 322 35.3 7.1 3.5 neg 16.6 7.2 688 757 166 182

TGK-2 Russia TGKB RU common Buy USD 0.00120 0.00136 0.00100 36% 1 461 1 249 16.5 4.8 2.9 65.5 10.1 5.6 484 664 123 169

TGK-2 Russia TGKBP RU preferred Hold USD 0.000734 0.000832 0.000725 15%

Mosenergo

(TGK-3)Russia MSNG RU common Buy USD 0.244 0.278 0.177 57% 7 036 6 840 9.2 5.4 4.6 23.0 10.4 8.8 615 966 107 169

TGK-4 Russia TGKD RU common Buy USD 0.00125 0.00142 0.00105 35% 2 044 1 879 18.3 6.8 3.7 136.5 16.4 7.2 567 763 148 198

TGK-4 Russia TGKDP RU preferred Buy USD 0.000623 0.000707 0.000555 27%

TGK-5 Russia TGKE RU common Buy USD 0.00145 0.00165 0.00078 112% 953 559 420.9 7.0 2.5 neg 36.7 7.4 227 628 51 140

TGK-6 Russia TGKF RU common Buy USD 0.00089 0.00102 0.00073 39% 1 357 972 62.7 13.3 8.5 neg 178.7 40.0 309 454 78 114

TGK-7 Russia TGKG RU common Buy USD 0.148 0.168 0.090 87% 2 698 2 431 15.9 8.4 5.6 119.7 22.2 11.6 353 676 91 174

TGK-8 Russia TGKH RU common Reduce USD 0.00128 0.00146 0.00167 -12% 3 433 2 771 52.6 18.1 6.7 neg 62.4 15.2 769 606 188 148

TGK-9 Russia TGKI RU common Buy USD 0.000390 0.000439 0.000300 46% 2 347 1 867 11.8 7.0 6.7 34.1 16.1 16.3 569 877 115 177

TGK-10 Russia TGKJ RU common Buy USD 5.87 6.65 4.61 44% 4 051 2 335 18.1 7.1 4.3 107.6 24.8 13.3 718 1 179 113 185

TGK-11 Russia TGKK RU common Buy USD 0.00184 0.00215 0.00112 92% 574 583 5.1 4.9 5.7 9.7 9.7 13.9 288 535 72 134

Kuzbassenergo

(TGK-12)Russia KZBE RU common Buy USD 0.0428 0.0490 0.0235 109% 1 656 1 433 24.6 12.5 8.2 neg 122.2 45.1 327 716 62 135

TGK-13 Russia TGKM RU common Buy USD 0.0173 0.0198 0.0083 140% 1 313 1 157 24.1 11.1 9.5 neg 38.8 16.8 467 765 100 164

TGK-14 Russia TGKN RU common Buy USD 0.000434 0.000501 0.000325 54% 253 245 6.8 6.5 6.7 13.4 13.4 14.2 381 578 104 157

Kuban Gen. Co. Russia KBGR RU common Buy USD 16.8 19.1 11.5 66% 205 213 304.3 18.2 1.8 neg neg 2.8 306 494 40 65

Russian thermal gen. co. average 44.4 9.7 6.0 61.2 36.4 15.0 446 699 98 151

WA 28.6 9.5 5.6 62.0 29.3 13.4 497 755 105 156

Russian hydro generation companies

RusHydro HYDR RU common Buy USD 0.096 0.110 0.085 29% 22 521 19 562 11.9 8.4 5.9 22.3 15.4 10.6 780 1 038 234 298

Krasnoyarsk GES KRSG RU common Buy USD 8.5 10.1 4.0 153% 1 555 1 541 39.2 6.8 3.4 65.6 9.6 4.6 257 634 74 183

Russian hydro gen. co. average 25.6 7.6 4.6 44.0 12.5 7.6 518 836 154 241

WA 13.9 8.3 5.7 25.1 15.0 10.2 742 1 008 222 290

FV per

share 12m TP

EV /

Capacity,

USD/kW

EV /

Output

2007,EV / EBITDA P/E

Company Country BB ticker

Share

type

MCap,

USD

mn

EV,

USD

mnRating

Curr-

ency

Mid-

market

price as

of Jun

19, 2008

Upside

to TP


Figure 5:Summary, foreign generation

Source: Bloomberg, Glitnir estimates

2008e 2009e 2010e 2008e 2009e 2010e

Cur-

rent

Tar-

get

Cur-

rent

Tar-

get

GEM generators with major share of thermal capacity

Huaneng Power

International China 902 HK common HKD 6.56 6.69 -2% 14 113 19 884 8.8 7.7 6.8 21.6 18.0 17.2 552 542 124 122

Huadian Power

International China 1071 HK common HKD 2.59 2.47 5% 3 887 8 424 8.7 7.5 6.6 25.9 19.8 20.6 460 481 160 168

China Resources Power China 836 HK common HKD 25.0 21.8 15% 11 576 14 270 14.2 11.0 8.7 22.8 18.1 14.6 1 141 1 312 162 186

National Thermal Power

Corporation Ltd. India NATP IN common INR 212 169 26% 31 863 34 957 14.0 12.3 11.2 17.9 16.6 15.2 1 278 1 607 185 233

Kot Addu Power Co. Pakistan KAPCO PA common PKR 51.3 48.9 5% 642 750 n/a n/a n/a 8.1 7.8 n/a 469 492 92 96

Zorlu Enerji Ele Turkey ZOREN TI common TRY 7.94 5.53 44% 370 701 11.4 4.7 3.0 neg 5.8 3.8 1 669 2 397 284 408

GEM thermal gen. co. average 11.4 8.7 7.2 19.2 14.4 14.3 928 1 139 168 202

WA 12.1 10.3 9.0 20.0 17.2 15.8 979 1 162 163 190

Developped markets generators with major share of thermal capacity

TransAlta Corporation Canada TA CN common CAD 35.6 36.8 -3% 7 232 10 103 9.6 9.1 9.0 24.1 20.5 26.7 939 907 210 202

Drax Group UK DRX LN common GBp 617 745 -17% 4 986 5 651 7.5 7.5 6.8 10.6 11.1 9.8 1 413 1 171 210 174

International Power UK IPR LN common GBp 461 423 9% 12 560 22 075 8.9 8.3 8.2 14.8 13.5 13.0 708 772 n/a n/a

NRG USA NRG US common USD 51.9 43.5 19% 10 256 18 792 8.4 7.6 7.1 17.0 14.1 12.4 779 930 393 469

Calpine Corp USA CPN US common USD 22.6 22.9 -1% 9 627 19 432 11.3 10.9 9.3 26.7 21.6 16.6 816 807 215 213

Developped markets thermal gen. co. average 9.1 8.7 8.1 18.6 16.2 15.7 931 917 257 265

WA 9.4 8.8 8.2 18.9 16.2 15.5 836 868 276 296

Foreign Hydro

Cia Energetica de

Sao Paulo Brazil CESP BR common BRL 35.7 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Jaiprakash Hydro

Power Ltd India JHPL IN common INR 48.0 55.4 -13% 629 854 13.7 14.5 14.9 18.1 20.8 20.9 2 846 2 467 708 614

Tractebel Energia SA Brazil TBLE3 BZ common BRL 27.4 23.6 16% 9 668 10 196 8.7 7.9 7.3 15.1 14.0 12.1 1 740 2 017 478 554

AES Tiete Brazil GETI3 BZ common BRL 22.1 19.0 17% 4 251 4 538 6.4 6.1 6.0 10.9 10.5 10.0 1 712 1 996 364 424

International hydro gen. co. average 9.5 9.4 14.7 15.1 14.3 2 099 2 160 517 531

WA 7.7 7.3 14.0 13.3 11.9 1 792 2 036 457 519

Bloomberg consensus target prices and earnings estimates used for foreign peers

Mid-

market

price as

of Jun

19, 2008

Upside

to TP

FV per

share 12m TP

EV / EBITDA P/EMCap,

USD

mn

EV,

USD

mn

EV /

Capacity,

USD/kW

EV / Output

2007,

USD/MWh


Share

type Rating

Curr-

ency


Figure 6: Valuation summary, integrated


Cur-

rent

Tar-

get

Cur-

rent

Tar-

get

Russian integrated uilities

Bashkirenergo Russia BEGY RU common Buy USD 3.52 4.04 1.59 155% 1 730 1 780 1.9 43.9 neg 346 831 70 168

Bashkirenergo Russia BEGYP RU preferred Hold USD 1.50 1.72 1.56 11%

Irkutskenergo Russia IRGZ RU common Buy USD 1.84 2.14 0.88 143% 4 195 4 217 4.9 14.3 48.9 327 776 72 171

Novosibirskenergo Russia NVNG RU common Buy USD 138 159 71 125% 1 071 1 294 2.1 36.6 neg 513 1 022 126 250

Novosibirskenergo Russia NVNGP RU preferred Buy USD 78.1 89.7 46.0 95%

Far East Energy Company Russia DVEC RU common Buy USD 0.105 0.119 0.073 64% 1 249 2 091 1.7 14.3 868.0 358 450 108 135

Russian integrated utilities average 2.6 27.3 458.4 386 770 94 181

WA 3.2 23.0 236.8 363 748 87 173

Russian integrated utilities expected to be listed in 2H08

InterRAO Russia common USD 0.00222 0.00252

Far East Energy Holding Russia common USD 0.0596 0.0672 0.0600 12%

Far East Energy Holding Russia preferred USD 0.0417 0.0471

GEM integrated uilities

KEPCO South Korea 015760 KS common KRW 29 300 30 875 -5% 19 214 33 590 1.1 13.7 11.5 557 529 88 84

CEZ Czech Republic CEZ CP common CZK 1 425 1 364 5% 51 991 57 309 6.7 15.2 25.4 4 010 4 191 777 812

Cia Energetica de Minas Gerais Brazil CMIG3 BZ common BRL n/a 33.2 n/a 11 276 14 767 2.8 8.0 12.7 2 211 n/a 459 n/a

Cia. Paranaense de Energia Brazil CPLE3 BZ common BRL n/a 29.6 n/a 5 197 5 597 2.0 5.4 9.2 1 230 n/a 540 n/a

Endesa Chile Chile ENDESA CI common CLP 882 768 15% 13 132 18 204 5.5 12.4 35.6 3 809 4 375 970 1 114

HongKong Electric Holdings Hong Kong 6 HK common HKD 45.5 47.7 -5% 13 014 13 182 8.2 10.5 13.6 3 510 3 351 731 698

CLP Holdings Ltd Hong Kong 2 HK common HKD 68.3 66.0 4% 20 284 26 655 4.1 13.3 14.9 2 999 3 106 998 1 034

Tata Power Co Ltd India TPWR IN common INR 1 496 1 299 15% 6 657 7 608 6.3 26.4 39.7 3 275 3 774 553 638

Tenaga Nasional Bhd Malaysia TNB MK common MYR 9.70 8.03 21% 10 759 16 107 2.4 6.7 9.3 1 399 1 691 n/a n/a

GEM integrated utilities average 4.3 12.4 19.1 2 556 3 003 640 730

MCap weighted average 4.5 13.0 20.1 2 751 3 015 652 710

Developed markets integrated uilities

EDF France EDF FP common EUR 87.5 63.4 38% 179 412 226 135 2.8 10.6 23.3 1 785 2 463 370 511

Endesa SA Spain ELE SM common EUR 37.3 33.3 12% 54 779 94 980 3.9 10.6 15.0 1 932 2 169 516 580

Energias de Portugal SA Portugal EDP PL common EUR 4.69 3.60 30% 20 418 40 265 2.9 11.4 16.4 2 572 3 351 828 1 079

Fortum Oyj Finland FUM1V FH common EUR 32.2 31.4 3% 43 298 52 892 8.6 19.4 20.4 4 844 4 969 1 013 1 040

Iberdrola SA Spain IBE SM common EUR 10.6 8.84 20% 68 568 114 476 4.7 15.1 21.3 2 693 3 235 927 1 114

RWE AG Germany RWE GR common EUR 90.8 81.2 12% 69 821 72 177 1.3 6.8 19.2 1 621 1 813 334 374

Scottish & Southern Energy PLC Britain SSE LN common GBp 1 614 1 442 12% 24 728 31 958 1.0 11.6 14.1 3 190 3 572 686 768

Union Fenosa SA Spain UNF SM common EUR 47.5 39.8 19% 18 830 36 178 4.4 12.8 14.0 3 107 3 712 737 881

Developed markets integrated utilities average 3.7 12.3 18.0 2 718 3 161 677 793

WA 3.6 11.9 20.1 2 371 2 855 596 717

* OTC forward price for Far East Energy Holding


FV per

share 12m TP

Market

price as

of Jun

19, 2008*Company Country BB ticker

Share

type Rating

Cur-

rency

Upside

to TP

MCap,

USD mn

EV /

Capacity,

USD/kW

EV / Output

2007,

USD/MWhEV /

Sales

2007

EV /

EBITDA

2007

P/E

2007

EV,

USD mn


Figure 7: Valuation summary, distribution


2006 2011e 2006 2011e 2006 2011e

Cur-

rent

Tar-

get

Cur-

rent

Tar-

get

MRSK Center Russia MRKC RU common Buy USD 0.0744 0.0840 0.0519 62% 2 191 2 303 2.5 0.9 13.1 2.0 33.3 4.6 1.5 38 60 6.3 9.8

MRSK South Russia n/a common n/a USD 0.0270 0.0306 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 50 n/a 9.9

MRSK North Caucasus Russia MRKK RU common Buy USD 24.8 28.1 11.5 145% 340 358 1.2 0.4 37.2 1.0 neg 2.1 0.7 26 60 3.4 8.0

MRSK Center and Volga Russia MRKP RU common Buy USD 0.0201 0.0226 0.0141 61% 1 583 1 600 2.0 0.8 11.7 2.0 72.1 4.7 1.4 27 42 6.4 10.1

MRSK North-West Russia MRKZ RU common Buy USD 0.0192 0.0218 0.0111 96% 1 063 1 103 1.6 0.7 9.3 1.8 40.9 4.0 1.1 26 50 6.8 12.9

MRSK Siberia Russia MRKS RU common Buy USD 0.0257 0.0291 0.0183 59% 1 635 1 768 1.7 0.7 11.8 2.0 neg 4.5 1.5 19 31 6.8 11.0

MRSK Urals Russia MRKU RU common Buy USD 0.0211 0.0239 0.0191 26% 1 666 1 722 1.6 0.7 15.5 2.5 58.9 5.5 1.5 20 27 12.2 16.6

MRSK Volga Russia MRKV RU common Buy USD 0.0168 0.0191 0.0073 162% 1 304 1 325 1.5 0.6 10.1 1.4 64.2 3.0 1.2 22 55 6.3 15.9

Moscow Unified Dis. Co. Russia MSRS RU common Hold USD 0.0795 0.0898 0.0885 1% 2 500 2 789 3.0 1.3 10.3 2.9 23.9 7.0 1.4 41 41 37.7 38.1

Moscow City Dis. Co. Russia MGRS RU common Hold USD 0.0576 0.0650 0.0630 3% 1 780 1 705 4.6 1.5 12.9 2.4 18.0 6.6 2.3 47 48 28.2 28.5

Lenenergo Russia LSNG RU common Reduce USD 1.372 1.549 1.745 -11% 1 754 1 635 4.2 1.5 14.9 2.7 104.3 7.3 1.4 55 47 31.4 26.9

Lenenergo Russia LSNGP RU preferred Reduce USD 1.084 1.224 1.375 -11%

Kurganenergo Russia KRGE RU common Buy USD 0.627 0.710 0.460 54% 74 89 0.5 n/a 6.0 n/a n/a n/a 0.3 22 27 3.3 4.0

Kurganenergo Russia KRGEP RU preferred Buy USD 0.475 0.539 0.428 26%

Tomsk Dis. Co. Russia TORS RU common Reduce USD 0.0172 0.0195 0.0255 -24% 111 111 1.4 n/a 11.5 n/a 403.0 n/a 1.0 18 13 7.0 5.2

Tomsk Dis. Co. Russia TORSP RU preferred Reduce USD 0.0151 0.0172 0.0245 -30%

Kubanenergo Russia KUBE RU common Reduce USD 19.7 22.4 27.8 -19% 496 611 1.4 n/a 12.4 n/a 203.2 n/a 1.6 38 32 7.2 6.1

Russian dis. co. average 2.4 0.9 14.7 2.1 52.0 4.9 1.4 32 46 14.5 15.6

WA 2.6 1.0 12.8 2.2 49.7 5.4 1.5 34 45 17.1 16.8

Russian distribution companies expected to be listed in 2H08

MRSK Holding Russia common USD 0.282 0.318 0.230 38%

MRSK Holding Russia preferred USD 0.197 0.223

Foreign distribution companies

ELMU Rt. Hungary ELMU HB common HUF n/a 23 473 n/a 939 1 077 1.1 n/a 6.8 n/a 13.6 n/a 2.1 146 n/a 48.4 n/a

EMASZ Hungary EMASZ HB common HUF n/a 20 320 n/a 409 474 1.1 n/a 8.9 n/a 19.6 n/a 2.0 163 n/a 21.3 n/a

Prazska EnergetikaCzech

RepublicPREN CP common CZK n/a 6 350 n/a 1 584 1 541 2.5 n/a 11.5 n/a 20.8 n/a 3.1 266 n/a 133.5 n/a

Eletropaulo Metropolitana

Eletricidade de Sao

Paulo SA

Brazil ELPL6 BZ common BRL 39.96 38.08 5% 3 664 4 029 1.0 0.8 6.1 4.0 21.4 9.0 3.6 127 134 95.3 100.0

Vakaru Skirstomieji Tinklai Lithuania RST1L LH common LTL n/a 3.82 n/a 853 929 2.7 n/a 12.4 n/a 94.5 n/a 1.2 252 n/a 16.3 n/a

CegedelLuxem-

bourg VST1L LH commonLTL

n/a 753 n/a 1 254 1 293 3.8 n/a 11.4 n/a 57.9 n/a 2.3 278 n/a 180.1 n/a

International dis. co. average 2.0 9.5 38.0 2.4 205 82.5

WA 1.8 8.6 32.8 2.8 187 96.3

Russian Dis. Co. premium / (discount) to foreign peers 39% 49% 52% -48% -82%

* OTC forward price for MRSK Holding



Share

type Rating

FV per

share

Cur-

rency

Market

price

as of

Jun 19,

2008*12m TP

Up-

side

to TP

EV,

USD

mn

MCap,

USD

mn

EV / EBITDA

EV /

Through-

put 2006,

USD/MWhEV/Sales

P/B,

2007e

P/E

EV / Grid

length,

USD th/km


Figure 8: Valuation summary, transmission



Share

type Rating

Cur-

rency

FV per

share,

USD

12m

TP

Market

price as

of Jun

19,

2008*

Up-

side

to TP

MCap,

USD

mn

EV,

USD

mn

EV /

Sales

2006

EV /

EBITDA

2006

P/E

2006

P/B

2006

EV / Grid

length,

USD

thous.

/km

EV /

Through-

put 2006,

USD/

MWh

Russian trans. co.

FSK n/a common n/a USD 0.0229 0.0258 0.0235 10% 12 414 10 323 3.0 5.5 n/a 2.7 86 23.0

Vologda Trans. Co. VOMS RU common Hold USD 1.56 1.75 1.70 3% 36 n/a

Kuban Trans. Co. KNMS RU common Reduce USD 0.288 0.323 0.475 -32% 8 n/a

Tomsk Trans. Co. TOMS RU common Reduce USD 0.0102 0.0114 0.0158 -28% 59 66

Tomsk Trans. Co. TOMSP RUpreferred Reduce USD 0.0093 0.0105 0.0135 -23%

Foreign trans. co.

Terna Rete Elettrica

Nazionale SpAItaly TRN IM common EUR 3.05 2.88 6% 8 991 13 156 8.5 11.9 18.4 3.2 317 41.6

Cia de Transmissao

de Energia Eletrica PaulistaBrazil

TRPL3 BZ common BRL n/a 46.99 n/a 4 394 4 609 7.6 43.6 81.2 2.5 380 35.5

Interconexion Electrica SALatin

AmericaISA CB common COP n/a 7 710 n/a 5 029 5 027 5.6 10.1 78.9 1.7 134 96.0

Lietuvos Energija Lithuaniua LEN1L LH common LTL n/a 3.55 n/a 1 086 1 106 3.1 16.0 159.6 1.3 166 89.6

Red Electrica de Espana Spain REE SM common EUR 49.87 43.43 15% 9 117 n/a n/a n/a 36.3 6.8 n/a n/a

International trans. co. avg. 6.2 20.4 84.5 2.2 249 65.7

WA 7.5 17.8 56.0 2.6 284 54.1

Russian FSK premium / (discount) to foreign peers -60% -69% n/a 5% -70% -57%

* For FSK - OTC forward price



Figure 9: Price performance


high low 5-day 1m 3m 6m 12m YTD 5-day 1m 3m 6m 12m YTD 5-day 1m 3m 6m 12m YTD

Generation companies

OGK-1 OGKA RU common 0.0903 0.123 0.080 0% -2% -17% -24% -19% -26% -3% 0% -33% -27% -35% -29% -2% -2% -11% -4% n/a -5%

OGK-2 OGKB RU common 0.0880 0.175 0.071 22% -2% -25% -37% -40% -42% 19% 0% -39% -40% -52% -45% 19% -2% -19% -21% n/a -26%

OGK-3 OGKC RU common 0.116 0.175 0.105 5% 12% 0% -23% -31% -23% 2% 14% -19% -27% -45% -26% 3% 12% 8% -3% n/a -1%

OGK-4 OGKD RU common 0.0800 0.134 0.079 -10% -10% -36% -40% -33% -40% -12% -8% -48% -43% -47% -43% -12% -10% -32% -25% n/a -24%

OGK-5 OGKE RU common 0.128 0.180 0.096 16% 13% 10% -26% -17% -26% 13% 16% -11% -30% -34% -30% 14% 13% 18% -7% n/a -6%

OGK-6 OGKF RU common 0.0780 0.166 0.070 -7% -15% -29% -46% -53% -46% -10% -13% -43% -49% -63% -48% -9% -15% -24% -32% n/a -30%

TGK-1 TGKA RU common 0.00134 0.00160 0.00120 0% -2% 6% 5% -8% 5% -3% 0% -14% 0% -27% 0% -2% -2% 13% 32% n/a 34%

TGK-2 TGKB RU common 0.00100 0.00122 0.00083 0% 5% -6% 1% -19% -1% -3% 8% -24% -4% -35% -6% -2% 5% 1% 27% n/a 27%

TGKBP RU preferred 0.000725 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Mosenergo (TGK-3) MSNG RU common 0.177 0.263 0.170 0% 3% -18% -27% -22% -24% -3% 5% -34% -30% -38% -28% -2% 3% -12% -8% n/a -3%

TGK-4 TGKD RU common 0.00105 0.00125 0.00100 0% 0% -14% -13% -5% -15% -3% 2% -30% -17% -24% -19% -2% 0% -8% 10% n/a 8%

TGKDP RU preferred 0.000555 0.00090 0.00051 0% 0% -12% -24% -22% -15% -3% 2% -29% -28% -37% -19% -2% 0% -6% -4% n/a 9%

TGK-5 TGKE RU common 0.000775 0.00140 0.00071 13% 7% -5% -13% -38% -12% 10% 9% -23% -17% -51% -16% 10% 7% 2% 9% n/a 13%

TGK-6 TGKF RU common 0.000730 0.00132 0.00070 -3% -18% -28% -37% -36% -37% -5% -16% -42% -40% -49% -40% -5% -18% -23% -21% n/a -19%

TGK-7 TGKG RU common 0.090 0.1285 0.0850 -1% -11% -15% -19% n/a -19% -3% -9% -31% -23% n/a -22% -3% -11% -9% 2% n/a 4%

TGK-8 TGKH RU common 0.00167 0.01350 0.00100 8% 4% 14% 28% 51% 19% 5% 6% -8% 21% 20% 13% 6% 4% 22% 61% n/a 52%

TGK-9 TGKI RU common 0.000300 0.00033 0.00026 0% 0% 14% 10% 10% 3% -3% 2% -8% 5% -12% -2% -2% 0% 22% 38% n/a 32%

TGK-10 TGKJ RU common 4.61 4.61 3.50 0% 2% 6% 15% 21% 13% -3% 4% -14% 10% -3% 8% -2% 2% 14% 45% n/a 44%

TGK-11 TGKK RU common 0.00112 0.00160 0.00110 0% -21% -15% -31% n/a -31% -3% -20% -31% -35% n/a -34% -2% -21% -9% -14% n/a -12%

Kuzbassenergo (TGK-12) KZBE RU common 0.0235 0.0365 0.0250 n/a 0% 0% -9% -28% -9% n/a 2% -19% -14% -42% -13% n/a 0% 7% 14% n/a 16%

TGK-13 TGKM RU common 0.00825 0.0117 0.0080 -2% -1% -5% -24% -27% -24% -5% 1% -23% -28% -41% -27% -4% -1% 2% -4% n/a -2%

TGK-14 TGKN RU common 0.000325 0.00040 0.00030 0% 0% 0% 0% 0% 0% -3% 2% -19% -5% -20% -5% -2% 0% 7% 26% n/a 28%

Kuban GC KBGR RU common 11.500 18.000 12.000 0% 0% -11% -17% -22% -23% -3% 2% -28% -21% -37% -26% -2% 0% -5% 4% n/a -1%

RusHydro HYDR RU common 0.0848 0.0930 0.0687 -2% -1% 12% n/a n/a n/a -4% 1% -9% n/a n/a n/a -4% -1% 20% n/a n/a n/a

Krasnoyarsk GES KRSG RU common 3.98 4.60 4.00 0% 0% -1% -2% -1% -2% -3% 2% -20% -7% -21% -7% -2% 0% 6% 23% n/a 25%

Integrated companies

Bashkirenergo BEGY RU common 1.59 2.15 1.50 -13% -13% -26% -29% -25% -29% -15% -11% -40% -33% -40% -33% -15% -13% -21% -11% n/a -9%

BEGYP RU preferred 1.56 1.22 1.15 0% 0% 0% 0% -6% 0% -3% 2% -19% -5% -25% -5% -2% 0% 7% 25% n/a 28%

Irkutskenergo IRGZ RU common 0.88 1.19 0.82 0% -4% -9% -22% -18% -28% -3% -2% -27% -26% -35% -31% -2% -4% -3% -2% n/a -7%

Novosibirskenergo NVNG RU common 70.5 70.0 50.0 0% 6% 6% 38% 15% 38% -3% 8% -14% 31% -8% 32% -2% 6% 14% 73% n/a 77%

NVNGP RU preferred 46.0 46.0 37.0 0% 14% 14% 24% 15% 24% -3% 17% -7% 18% -8% 19% -2% 14% 22% 56% n/a 59%

Far East Energy Co. DVEC RU common 0.073 0.124 0.065 3% 11% -28% -37% -38% -36% 0% 13% -42% -40% -51% -39% 1% 11% -23% -20% n/a -18%

Relative to RTS Electric Utilities

IndexRelative to RTS IndexPrice performance (absolute)

Company BB ticker

Share

type

1 year

Price as

of Jun

19, 2008


Price performance (continued)


high low 5-day 1m 3m 6m 12m YTD 5-day 1m 3m 6m 12m YTD 5-day 1m 3m 6m 12m YTD

Distribution companies

MRSK Center MRKC RU common 0.0519 0.0523 0.0510 3% n/a n/a n/a n/a n/a 0% n/a n/a n/a n/a n/a 0% n/a n/a n/a n/a n/a

MRSK North Caucasus MRKK RU common 11.5 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

MRSK Center and Volga MRKP RU common 0.0141 0.0142 0.0114 8% 23% n/a n/a n/a n/a 5% 25% n/a n/a n/a n/a 6% 23% n/a n/a n/a n/a

MRSK North-West MRKZ RU common 0.0111 0.0128 0.0100 -2% n/a n/a n/a n/a n/a -4% n/a n/a n/a n/a n/a -4% n/a n/a n/a n/a n/a

MRSK Siberia MRKS RU common 0.0183 0.0183 0.0160 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

MRSK Urals MRKU RU common 0.0191 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

MRSK Volga MRKV RU common 0.0073 0.0075 0.0074 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Moscow Unified Dist. Co. MSRS RU common 0.0885 0.1190 0.0655 -1% 9% -2% -11% -26% -16% -4% 12% -20% -15% -41% -19% -3% 9% 5% 13% n/a 8%

Moscow City Dist. Co. MGRS RU common 0.0630 0.0940 0.0495 -3% 4% -8% -23% -24% -32% -6% 7% -25% -27% -39% -35% -5% 4% -1% -3% n/a -12%

Lenenergo LSNG RU common 1.75 2.00 1.60 0% 0% -3% -8% 3% -10% -3% 2% -22% -13% -18% -14% -2% 0% 3% 16% n/a 16%

LSNGP RU preferred 1.38 1.65 1.24 0% 0% -15% -1% 6% -19% -3% 2% -31% -6% -15% -23% -2% 0% -9% 24% n/a 3%

Kurganenergo KRGE RU common 0.460 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

KRGEP RU preferred 0.428 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Tomsk Dist. Co. TORS RU common 0.0255 0.0325 0.0210 0% 0% -3% -3% -23% -3% -3% 2% -22% -8% -38% -8% -2% 0% 4% 22% n/a 24%

TORSP RU preferred 0.0245 0.0330 0.0225 0% 0% 12% 27% 47% 27% -3% 2% -9% 21% 17% 21% -2% 0% 20% 60% n/a 63%

Kubanenergo KUBE RU common 27.8 38.0 28.0 0% 22% -4% -14% 3% -13% -3% 25% -23% -18% -18% -17% -2% 22% 2% 9% n/a 12%

Transmission companies

Vologda Trans. Co. VOMS RU common 1.70 3.30 1.65 0% 6% 3% -13% -31% -13% -3% 8% -17% -17% -45% -17% -2% 6% 10% 10% n/a 12%

Kuban Trans. Co. KNMS RU common n/a 0.700 0.455 0% 0% -24% n/a n/a n/a 1% 4% -36% n/a n/a n/a -4% 1% -22% n/a n/a n/a

Tomsk Trans. Co. TOMS RU common 0.0158 0.0300 0.0100 0% 55% -23% -14% -50% -47% -3% 58% -37% -18% -60% -49% -2% 55% -17% 8% n/a -32%

Tomsk Trans. Co. TOMSP RU preferred 0.0135 0.0215 0.0150 0% 0% -6% -17% -25% -17% -3% 2% -24% -21% -40% -20% -2% 0% 0% 5% n/a 7%

Relative to RTS Electric Utilities

IndexRelative to RTS IndexPrice performance (absolute)

Company BB ticker

Share

type

1 year

Price as

of Jun

19, 2008


Overview: Russian utilities at a glance

Russia’s utilities sector is the fourth largest in the world in terms of both installed capacity and

electricity production.

Figure 10: Capacity and generation by country

Installed capacity Electricity generation

Source: EIA Source: EIA

The generation segment is dominated by thermal power plants; hydroelectric and nuclear plants

contribute 34% to total installed capacity and electricity production. On average, nuclear plants

have the highest load factors, while hydroelectric plants have the lowest.

Figure 11: Capacity and generation by type, 2007

Installed capacity Electricity generation

Source: UES, Glitnir estimates Source: UES, Glitnir estimates

Figure 12: Average load factor by type of capacity, 2007

Source: UES

The main fuel used by thermal power plants is gas, followed by coal; fuel oil is usually used only

as a reserve and kindling fuel.

0

200

400

600

800

1 000

1 200

US

A

Ch

ina

Ja

pa

n

Ru

ssia

Ind

ia

Ge

rma

ny

Ca

na

da

Fra

nce

Bra

zil

Ukra

ine

Ita

ly

Sp

ain

GW

0

500

1 000

1 500

2 000

2 500

3 000

3 500

4 000

4 500

US

A

Ch

ina

Ja

pa

n

Ru

ssia

Ind

ia

Ca

na

da

Ge

rma

ny

Fra

nce

Bra

zil

UK

S. K

ore

a

Ita

ly

k G

Wh

Thermal66%

Hydro22%

Nuclear12%

Thermal67%

Hydro17%

Nuclear16%

78%

43%

55%50%

0%10%20%30%40%50%60%70%80%90%

Nuclear Hydro Thermal GRES

Thermal CHP


Figure 13: Fuel balance in Russia, 2006

Source: UES

The majority of power is consumed by industry; residential consumers account for only about

20% of total supplied electricity.

Figure 14: Electricity consumption breakdown, 2007

Source: UES

Russia’s grid assets are broken down into transmission and distribution. Transmission is

classified as a high-voltage grid (220 kV and above), while distribution is classified as a low-

voltage grid (110 kV and below).

Russia’s transmission assets encompass 120 530 km of high-voltage power grids with a total

transformer capacity of 295 691 MVA. In 2006, transmission companies transferred 448 TWh of

electricity.

Distribution assets are represented by 1 970 000 km of low-voltage grids and 336 000 MVA of

transformer capacity. In 2006 distribution companies transferred 672 TWh of electricity to

consumers.

Gas70%

Coal26%

Fuel oil3%Other

1%

Industrial consumers

62%

Agriculture2%

Transportation6%

Non-industrial consumers,

other

10%

Households20%


Lack of capacity: Main driver behind the reform

Starting from the 1980s, construction of new plants began to lag behind growth in demand for

electricity. Reserve margins began to shrink, hitting bottom in 1990.

The political transition process of the 1990s caused a sharp drop in industrial output and an

overall economic slowdown. This in turn triggered a rapid reduction in power consumption, and

power plants had excess capacity for some time. This fact coupled with the overall uneasy

political situation explains why new additions of capacity reached a low in the 1990s.

However as the Russian economy revitalized, in early 1999 power consumption started to grow,

demonstrating a healthy and accelerated CAGR of 2.3% over 1999-2007. Consumption

increased at a record high of 4.5% in 2006.

Figure 15: GDP and power consumption

Source: Rosstat, Glitnir calculations

Figure 16: Installed electric capacity, maximum load, reserve margin, Russia total

Source: UES

Power consumption peaked during the unusually cold winter of 2005-2006, revealing the true

extent of the country’s power supply deficit. Unified Energy Systems (UES), the largest Russian

utility provider, was forced to introduce limits on power consumption in 16 regions across Russia.

1.4%-5.3%

6.4%

10.0%5.1%

4.7%

7.3%7.2%

6.4%

7.4%

8.1%

-1.5% -0.8%2.3%

3.7%1.5%0.0%

2.8% 1.7% 2.3%4.5%

2.0%

-10%

0%

10%

20%

30%

40%

50%

60%

70%

80%

1996 1998 2000 2002 2004 2006

Cumulative GDP growth, % Cumulative power consumption, %

0

40

80

120

160

200

240

GW

Maximum load

Installed electric capacity

0%

20%

40%

1992 1994 1996 1998 2000 2002 2004 2006

Reserve margin, %


Figure 17: Peak consumption, January 23, 2006

Source: UES

As over the last 20 years only marginal volumes of new capacity were commissioned, most

Russian power plants are heavily worn out, with an average age of 30.5 years. Over half of

currently operating power plants were built in the 1960s and ’70s. Given the total government

regulation and state ownership in the sector, utilities were underfinanced for decades.

Depreciation of assets reached 50-70% across various segments.

Figure 18: Split of capacity by period of commissioning

Source: UES

Figure 19: Asset depreciation by segment

Source: UES

Another consequence of the underfinancing was that Russia’s electricity and utility assets have

remained at more or less the same technological level since the Soviet era, meaning they are

much less efficient and less reliable than modern technology. This low technological level is

reflected in high fuel burn rates, high rates of loss in the power grid, and frequent breakdowns.

0

10

20

30

40

50

Volga Siberia South North-West

Urals Center

GW

Reserve Maximum load

0

10

20

30

40

50

60

70

Before 1950

1950s 1960s 1970s 1980s 1990s-2000s

GW

Nuclear Hydro Thermal

0%

10%

20%

30%

40%

50%

60%

70%

80%

Electricity and heat

generation

Electricity transmission

Electricity distribution

Heating grid


Figure 20: Average fuel burn rate, Russia total

Source: UES, Glitnir estimates

In order to meet the growing economy’s electricity needs, the government has outlined a strategy

to build new power stations and secure reliable power supply. This strategy was documented in

the ―General Scheme for Power Facility Allocation,‖ which was first drafted in 2007 and finally

approved by the government in February 2008. The strategy envisages an astronomical USD

880 bn to be spent on overhauling the power sector in from 2006 to 2020. As a comparison, the

Russian GDP in 2007 was USD 1 290 bn; as of YE07, combined national savings and

investment funds (which accumulate tax proceeds from oil and gas exports) held USD 157 bn in

assets and the Central Bank of Russia’s international reserves were USD 476 bn.

Figure 21: Capex requirements, government base scenario

Source: Ministry of Industry and Energy

When faced with the looming capex needs, UES and state decision-makers had no choice but to

implement a reform in order to attract private money and stimulate improvements in reliability and

operational efficiency in the sector.

200

220

240

260

280

300

320

340

360

1998 2007

g/k

Wh

New coal-f ired plant

New gas-f ired plant

0

100

200

300

400

500

600

2006-2015 2016-2020

US

D b

n

Hydro Nuclear Distribution

Transmission Thermal


The reform

The goals and tasks of the power-sector reform were first outlined in Government Decree No.

526 on July 11, 2001, and subsequently altered and detailed in 2003 in UES’s 5+5 Strategy for

2005-2008, as well as in various legislative documents.

The main goals established in these documents were:

1. To increase the efficiency of power companies

2. To promote development by stimulating investments

3. To secure reliable and uninterruptable power supply

The reform documents also outlined several tasks for achieving these goals, which can be fit into

three main groups:

1. Restructuring by business type, meaning the separation of naturally monopolistic from

potentially competitive businesses. Power grids (transmission and distribution) are

considered natural monopolies, while generation and power supply companies are

considered competitive.

2. Privatisation of companies deemed ―competitive‖ (with the exception of hydroelectric

generation)

3. Switch to market-based pricing

Restructuring

Pre-reform structure

Prior to the reform, the structure of the Russian utilities sector had remained virtually unchanged

since the early 1990s. The sector consisted of the giant holding UES, four vertically integrated

utility companies that were independent from the state (Bashkirenergo, Irkutskenergo,

Novosibirskenergo, and Tatenergo), and a sole nuclear-stations operator 100% controlled by the

state (Rosenergoatom).

UES held 45-100% stakes in 72 vertically integrated regional joint-stock energy companies (AO-

energos) and 50-100% stakes in 44 stand-alone power stations. Each AO-energo owned

generation, transmission, distribution, and supply assets in a particular region of Russia.

The restructuring process

Given the pre-reform structure of the sector, the division of assets into competitive and non-

competitive was a complicated task. Before the reform, most utility companies were AO-energos,

each of which provided a complete electricity-delivery chain from generation to distribution and

sales to end consumers. The restructuring involved the breaking up of all 72 AO-energos into

several individual companies, each of which represented a separate line of business:

1. Regional generation companies and large stand-alone condensing power plants

(GRESs), which represented electricity and heat generation

2. Regional transmission companies, which represented transmission (high-voltage

power grids of 220 kV and above)

3. Regional distribution companies, which represented distribution (low-voltage power

grids of 110 kV and below)

4. Supply companies, which bought electricity from generators, and sold electricity to

end consumers

5. Other companies, which represented service, engineering, and other non-core areas

The AO-energos conducted pro-rata spinoffs of several companies that represented generation,

transmission, supply, and service assets; after the spinoffs, the companies typically maintained

only distribution assets.


Figure 22: UES reorganization

UES structure before reorganization UES restructuring process Industry structure after reorganization



The restructuring scheme stipulated that the spun-off entities and assets controlled directly by

UES were to be merged into companies of the sector’s target structure as follows:

1. 32 GRESs spun off from AO-energos and those controlled by UES directly

were to be merged into six wholesale generation companies (OGKs). The

OGKs were designed to own large condensing power stations, each located

in a different region of the country; the size and quality of assets for the

OGKs was to be as equal as possible in order to promote fair competition

among the companies in the future.

2. 57 regional generation companies spun off from AO-energos were to be

merged into 14 territorial generation companies (TGKs). TGKs have smaller

cogeneration power plants relative to OGKs, which produce heat in addition

to electricity. All of the TGKs’ power stations operate in the same

geographical region (or neighbouring regions); TGKs can differ vastly in size.

3. Hydroelectric generation plants spun off from AO-energos and those owned

by UES directly were to be merged into RusHydro (also known as

HydroOGK).

4. 56 regional transmission companies were to be merged into the Federal Grid

Company (FSK).

5. 57 regional distribution companies were to be merged into nine interregional

distribution companies (MRSKs).

Exceptions to the typical restructuring scheme

Mosenergo and Kuzbassenergo maintained generation assets after the spinoffs and became

TGKs.

Tomskenergo maintained generation assets and after the merger with Omsk Generation

Company became TGK-11.

TGK-1 and TGK-8 did not transfer their hydroelectric plants to RusHydro.

Lenenergo and Tyumenenergo will not be merged with any other regional distribution companies,

and therefore can be treated as interregional distribution companies.

Samaraenergo, Ulyanovskenergo, and Saratovenergo spun off generation, transmission, and

distribution assets but maintained their supply businesses.

Utility companies in the Far East district and AO-energos that are isolated from the united power

grid have a different restructuring scheme (see ―Formation of target structure: Far East power

utilities‖ for details).

Overall, the restructuring process involved an increase in the number of utility companies from

about 90 to about 230, with their subsequent consolidation into about 50 companies of the target

sector structure.

As of the date of this report, all six OGKs, all 14 TGKs, RusHydro, InterRAO, and 10 MRSKs

have completed restructuring. Regional transmission companies are expected to be consolidated

into FSK simultaneously with the UES breakup on July 1, 2008.

Formation of target sector structure


As a result of a series of mergers in 2006, 32 large condensing power plants (GRESs) controlled

by UES and AO-energos were fully consolidated into six OGKs. All six OGKs were listed on

Russian stock exchanges in 2005-2006.

All 14 TGKs were formed and listed on Russian stock exchanges in 2005-2007. The majority of

TGKs have the fully consolidated generation assets of former AO-energos, with a few

exceptions: there is a certain minority interest in Murmansk CHP, Kuban Generation Company,

and Kurgan Generation Company, which are subsidiaries of TGK-1, TGK-8, and TGK-10,

respectively.


Figure 23: Map of generation companies

Source: Company data


RusHydro

RusHydro (also known as HydroOGK) was established in 2004 as a 100% subsidiary of UES.

UES contributed its stakes in hydroelectric generation plants as well as cash to the charter

capital of RusHydro. In January 2008, RusHydro fully consolidated its 20 subsidiaries.

RusHydro plans to conduct an additional share issue in June 2008, which will be paid for with

certain UES assets, including Irganaiskaya GES, Kaskad Nizhnecherekskikh GES,

Kolymaenergo, and Krasnoyarskenergosbyt.

In July 2008, RusHydro plans to hold another additional share issue related to the UES breakup

procedure. The purpose of the issue is to:

1. Distribute UES’s stake in RusHydro among former UES shareholders

2. Increase the state’s ownership in RusHydro by contributing a certain portion of cash

proceeds from the sale of state-attributed stakes in OGKs and TGKs to RusHydro’s

charter capital. (For details on the breakup procedure, see ―UES breakup") As a result,

the state is expected to receive a controlling stake in RusHydro.

The state will inject cash into the charter capital of RusHydro at USD 0.073 (RUB 1.73) per

share.

Figure 24: Consolidation of RusHydro



After the spinoffs of generation, transmission, and other assets, AO-energos were typically left

with distribution assets only, and were subsequently called regional distribution companies

(RSKs).

The government-approved target structure for the distribution segment envisioned 11

interregional distribution companies (MRSKs), which were to be controlled by the state through

MRSK Holding. The MRSKs were designed to be of relatively the same size.

Fifty-three of the total 57 RSKs have been consolidated into nine larger MRSKs. Two large

regional distribution companies in the Moscow region are to be merged to form MRSK Moscow

(see ―Consolidation of Moscow distribution grids‖), and two other large RSKs (Lenenergo and

Tyumenenergo) will remain separate companies.


Figure 25: Interregional power distribution companies (MRSKs)

Source: UES

So far consolidation has been completed for all MRSKs except Moscow MRSK. In the majority of

cases, RSKs were merged into MRSKs, meaning their shares were swapped into MRSK shares.

The exceptions are Kurganenergo, whose shareholders blocked the company’s merger into

MRSK Urals, and Kubanenergo and Tomsk Distribution Company, the mergers of which into

MRSK South and MRSK Siberia, respectively, were prohibited by the court (for details, see

―Appendix 1: Company-specific issues‖). Kurganenergo, Kubanenergo, and Tomsk Distribution

Company will continue to function as separate subsidiaries of their respective MRSKs.

After the consolidation is complete UES is expected to hold a controlling 45-100% stake in each

MRSK. When UES breaks up in July 2008, it will create the Interregional Distribution Company

Holding (MRSK Holding), a special entity that will inherit all of UES’s shares in the MRSKs. The

holding will be created on a pro-rata basis such that MRSK Holding’s shareholder structure will

mirror UES’s.

Figure 26: Distribution segment restructuring

Pre-consolidation Current After UES breakup


Shares of all MRSKs except MRSK South are currently trading on Russian exchanges; MRSK

South is expected to list its shares in June 2008. Also, MRSKs plan to launch GDR programs in

3Q08. Therefore investors can gain exposure to Russia’s distribution segment either through

shares of MRSKs or through shares of MRSK Holding, which is expected to be listed in 3Q08.

Consolidation of Moscow distribution grids

In November 2007, UES released the latest consolidation scheme for Moscow grids, according

to which consolidation will proceed in two stages. First, Moscow City Distribution Company

(MGESK) will merge into Moscow United Distribution Company (MOESK). Second, MOESK will

conduct an additional share issue, which will be paid for with distribution assets owned by the

Moscow city government. The consolidated company will be called MRSK Moscow.

MOESK and MGESK were appraised for the merger at USD 0.083 (RUB 1.96) and USD 0.060

(RUB 1.42) per share, respectively.

RSK 1

RSK 2

RSK 3

...

RSK 61

MRSK Holding

MRSK 1

MRSK 2

...

MRSK 11

43 - 100 %

stakes

50 - 70 %

stakes

UES

UES

52% 48%

State Minorities

52% 48%

State Minorities

MRSK 1

MRSK 2

...

MRSK 11

45 - 100 % stakes

UES

52% 48%

State Minorities

MRSK 1

MRSK 2

...

MRSK 11

MRSK Holding

MRSK 1

MRSK 2

...

MRSK 11

52% 48%

State Minorities

45 - 100 % stakes


Once all the consolidation procedures are complete UES’s heir, MRSK Holding, will be the

largest shareholder in MRSK Moscow, while the Moscow city government will hold roughly a

25% stake.

Lenenergo share issue in favour of St. Petersburg government

In August 2007, Lenenergo’s board of directors approved an additional share issue in favour of

the St. Petersburg city government. The issue will amount to 240 mn new common shares

(25.8% and 23.4% of enlarged common and total equity, respectively) at a price of RUB 37.44

(USD 1.52) per share. The issue was initiated on November 14, 2007, and is expected to end in

4Q08.

Figure 27: Lenenergo shareholder structure, post-additional share issue

Source: Company data, Glitnir estimates

Transmission

Before the industry reform began, transmission-grid assets were divided into those controlled by

UES directly and those owned by AO-energos. As part of the reform process, the AO-energos’

transmission assets were spun off on a pro-rata basis into 56 separate transmission companies

(MSKs).

The principles of the reform stipulate that all Russian transmission assets are to be consolidated

into the Federal Grid Company (FSK), of which a stake of at least 75% + 1 share is to be owned

by the state. Before the reform began, the state’s effective ownership in transmission assets was

45%. In order to increase its ownership of transmission assets to the required level, the state

plans to pump cash from the state budget and proceeds from the sale of UES’s state-attributed

stakes in thermal generation companies into FSK’s charter capital through a series of additional

share issues in 2006-2009. Proceeds from these issues are expected to finance FSK’s capex

program, which amounts to USD 39.7 bn for 2008-2012.

Figure 28: Additional share issues

Source: FSK, Glitnir estimates

FSK was established in 2002 as a wholly owned subsidiary of UES. Upon FSK’s establishment,

UES contributed the assets of the United National Power Grid, which were appraised at USD 5

bn.

In August 2006, FSK executed its first additional share issue under closed subscription in favour

of UES and the state. UES contributed cash and its remaining assets (including the United

National Power Grid and its stakes in 42 transmission companies spun off from AO-energos),

which totalled USD 15 bn. The state contributed USD 900 mn in cash. As a result, UES’s stake in

FSK decreased to 87.6% and the state received 12.4%.

FSK conducted a second additional share issue under closed subscription in favour of UES and

the state from August 2007 to March 2008. UES contributed cash and its stakes in the remaining

eight transmission companies; the state injected RUB 18.8 bn (USD 780 mn) from the budget.

UES44%

St. Petersburg government

23%VTB22%

Other minorities

11%

Start

date

End

date

New

shares,

mn

Placement

price,

USD

Initial issue 243 214 0.019

1st additional issue Jul 28, 2006 Mar 20, 2007 118 168 0.019

2nd additional issue Aug 24, 2007 Mar 17, 2008 114 965 0.025

3rd additional issue 2H08 2H08 698 170 0.024

4th additional issue 2009 2009 90 169 0.024

Current 476 347

Total expected after UES breakup 1 264 687


FSK’s third additional share issue is planned for June-July 2008. This issue will facilitate FSK’s

consolidation with the MSKs as well as procedures related to the UES breakup. In the process,

several transactions will take place simultaneously:

1. Minorities’ shares in 56 transmission companies will be swapped for shares in FSK.

2. UES shareholders will receive pro-rata stakes in FSK.

3. The state will pump additional funds into FSK (specifically, UES’s state-attributed

stakes in OGKs and TGKs or proceeds from the sales of these stakes).

4. UES will be merged into FSK. Assets remaining in UES after the breakup or proceeds

from the sales of such assets will be transferred to FSK.

The price of the third additional share issue is expected to be set at USD 0.0025 (RUB 0.59) per

share, which is equivalent to FSK’s appraised value as of April 1, 2007.

UES expects that following FSK’s fourth additional share issue, which is planned for 2009, state

ownership in FSK will increase to a stake of at least 75% + 1 share.

Figure 29: FSK consolidation


FSK shares are expected to be listed following UES’s breakup in July 2008.

Figure 30: Restructuring scheme, timeline

Source: FSK, UES

Far East power utilities

Before the reform, power utilities in the Far East and North East regions of Russia were

represented by AO-energos that were separated from the united power grid of the rest of Russia.

Furthermore, some of these companies were completely isolated, and only a few in the Far East

region had the limited capability of free floating electricity.

2Q07 3Q07 4Q07 1Q08

Jun - Jul 2007MSK

appraisals

approvementPreparation of

fairness

opinion

Jul - Oct 2007UES BoDUES EGM

Oct 15-30, 2007FSK BoDMSK EGM

Dec 2007FSK EGM

MSK EGMs

Dec 07 - Mar 08MSK share

buyout

June 2008FSK

additional

share issue registration

June 2008Conversion of MSK shares

into FSK shares

3Q082Q08

JulyFSK local share

listing

FSK DRs issue

Jul - Aug 2008Registration of FSK additional

share issue report


Figure 31: Far East Energy Company and isolated AO-energos

Source: UES

In 2005, UES’s board of directors approved a scheme to create a 100%-subsidiary holding

company Far East Energy Company on the basis of the assets of Khabarovskenergo,

Amurenergo, Dalenergo, Lutek, and Southern Yakutskenergo. In 2007, Far East Energy

Company made an additional share issue and fully consolidated the aforementioned entities.

Figure 32: Reorganization of Far East and isolated AO-energos

Source: UES, Company data

Figure 33: Target structure of Far East and isolated AO-energos

Source: UES, Company data


Far East Energy Company established two 100%-owned subsidiaries which are distinguished by

type of activity: Far East Generation Company, which handles electricity and heat production,

and Far East Grid Company, which handles distribution.

Far East Energy Company’s transmission assets are to be contributed to FSK’s charter capital;

Far East Energy Company will thus swap them for shares in FSK.

Isolated energy companies do not fall under the requirements of the legislation to separate

assets by type of activity. Therefore these companies will remain vertically integrated for the time

being.

InterRAO

Figure 34: InterRAO Russian power plants

Source: InterRAO

As of YE07, InterRAO was a closed joint-stock company owned by UES (60%) and

Rosenergoatom (40%). The restructuring of InterRAO is proceeding in two stages. In the first

stage, which was completed on May 1, 2008, InterRAO, North-West CHP, and Ivanovo CCGT

were merged into Sochi TPP. In the second stage, which coincides with the UES breakup

procedure, Kalinigrad CHP-2 and InterRAO Holding (an interim holding spun off from UES) will

be merged into Sochi TPP. Sochi TPP has been renamed InterRAO.

As a result of these procedures, InterRAO will fully consolidate the four aforementioned power

plants, and all UES shareholders will receive pro-rata stakes in InterRAO.

Figure 35: Formation of InterRAO

Source: InterRAO, Glitnir estimates

Figure 36: InterRAO ownership after UES breakup

Source: InterRAO, Glitnir estimates


UES breakup

As the final step of the restructuring process, UES, the largest utility holding in Russia, will be

broken into parts and will cease to exist.

The first stage of the breakup was completed in September 2007, when UES spun off two

generation assets on a pro-rata basis: OGK-5 and TGK-5. The second and final stage will be in

June-July 2008, when UES will spin off all its core assets and simultaneously merge into FSK.

The second stage of the UES breakup will proceed in two steps:

1. UES will spin off 28 entities on a pro-rata basis. The record date for these spinoffs was

June 6.

2. After the spinoffs, UES will be merged into FSK. This merger is scheduled for July 1.

The first step is the most important, as it involves spinning off practically all of UES’s operating

assets. Of the spun-off entities, 23 are interim holdings, which will be merged into target

companies at the same time as the spinoffs. Of the interim holdings, 18 will be merged into 18

generation companies, two will be merged into RusHydro, two into FSK, and one into InterRAO.

Another five spun-off entities will represent stand-alone companies, and will not be merged into

any entities: three large minority holdings, MRSK Holding and Far East Energy Holding.

Figure 37: UES spinoff structure

Source: UES

For the purpose of the breakup, all UES shareholders were divided into three groups: the state,

large minority shareholders (Gazprom, Norilsk Nickel, and SUEK), and other minority

shareholders. Shareholders in the first two groups were given the right to exchange their

attributed stakes in generation companies with one another.

State holdings Mergers

1 State Holding

2 State RusHydro Holding 1 FSK

Minority holdings

3 Minority FSK Holding 2 RusHydro

4 Minority RusHydro Holding

5 OGK-1 Holding 3 OGK-1





10 TGK-1 Holding 8 TGK-1


12 TGK-3 (Mosenergo) Holding 10 TGK-3 (Mosenergo)



15 TGK-7 (Volzhskaya TGK) Holding 13 TGK-7 (Volzhskaya TGK)

16 TGK-8 (Yuzhnaya TGK) Holding 14 TGK-8 (Yuzhnaya TGK)




20 TGK-12 (Kuzbassenergo) Holding 18 TGK-12 (Kuzbassenergo)

21 TGK-13 (Yeniseyskaya TGK) Holding 19 TGK-13 (Yeniseyskaya TGK)


Large holdings

23 Center Energo Holding 21 Center Energo Holding

24 Sibenergo Holding 22 Sibenergo Holding

25 Intergeneration 23 Intergeneration

Shareholder holdings

26 MRSK Holding 24 MRSK Holding

27 Far East Energy Holding 25 Far East Energy Holding

28 InterRAO Holding 26 InterRAO

Merger

Mergers

28 holdings to be created with UES

stakes in OGKs/TGKs, RusHydro, FSK,

InterRAO transferred to these holdings

26 companies left after

UES breakup

Not to be merged


Figure 38: Large minorities’ equity swaps during UES breakup


State Gazprom

Norilsk

Nickel SUEK Other State Gazprom

Norilsk

Nickel SUEK Other State Gazprom

Norilsk

Nickel SUEK Other

OGK-1 92% 48% 10% 3% 1% 30% 14% -10% -3% -1% 0% 62% 0% 0% 0% 30%

OGK-2 81% 43% 9% 3% 1% 26% -43% 46% -3% -1% 0% 0% 55% 0% 0% 26%

OGK-3 37% 20% 4% 1% 0% 12% -9% -4% 13% 0% 0% 11% 0% 14% 0% 12%

OGK-4 90% 47% 9% 3% 1% 29% 13% -9% -3% -1% 0% 61% 0% 0% 0% 29%

OGK-6 93% 49% 10% 3% 1% 30% -38% 42% -3% -1% 0% 12% 52% 0% 0% 30%

RusHydro 100% 53% 11% 3% 1% 32% 11% -11% 0% 0% 0% 63% 0% 3% 1% 32%

TGK-1 56% 29% 6% 2% 1% 18% 8% -6% -2% -1% 0% 38% 0% 0% 0% 18%

TGK-2 49% 26% 5% 2% 0% 16% 7% -5% -2% 0% 0% 33% 0% 0% 0% 16%

TGK-3 (Mosenergo) 36% 19% 4% 1% 0% 12% 5% -4% -1% 0% 0% 25% 0% 0% 0% 12%

TGK-4 47% 25% 5% 2% 0% 15% 7% -5% -2% 0% 0% 32% 0% 0% 0% 15%

TGK-6 50% 27% 5% 2% 0% 16% 8% -5% -2% 0% 0% 34% 0% 0% 0% 16%

TGK-7 (Volzhskaya TGK ) 54% 29% 6% 2% 1% 18% 8% -6% -2% -1% 0% 37% 0% 0% 0% 18%

TGK-8 (Yuzhnaya TGK) 53% 28% 6% 2% 1% 17% 8% -6% -2% -1% 0% 36% 0% 0% 0% 17%

TGK-9 50% 26% 5% 2% 0% 16% 7% -5% -2% 0% 0% 34% 0% 0% 0% 16%

TGK-10 82% 43% 9% 3% 1% 26% 12% -9% -3% -1% 0% 55% 0% 0% 0% 26%

TGK-11 100% 53% 11% 3% 1% 32% 4% 0% -3% -1% 0% 57% 11% 0% 0% 32%

TGK-12 (Kuzbassenergo) 49% 26% 5% 2% 0% 16% -4% 0% -2% 6% 0% 22% 5% 0% 6% 16%

TGK-13 (Yeniseyskaya TGK) 57% 30% 6% 2% 1% 18% -12% 0% -2% 14% 0% 18% 6% 0% 15% 18%

TGK-14 50% 26% 5% 2% 0% 16% 7% -5% -2% 0% 0% 34% 0% 0% 0% 16%

Initial allocation Change of ownership After minority swaps

Company

UES

stake

as of

Apr 1,

2007


According to the breakup scheme, assets attributed to each group of shareholders are packaged

in a different way. Gazprom, Norilsk Nickel, and SUEK receive shares of specially established

entities Centerenergoholding, Intergeneration, and Sibenergoholding, respectively each of

which contains stakes in selected generation companies and FSK that are attributed to each

respective large minority shareholder. Other minority shareholders in UES receive stakes in

generation companies directly.

Stakes in generation companies attributed to the state (or cash proceeds from the sale of such

stakes) are divided into two parts. At the moment of the UES breakup, one part will be

contributed to the charter capital of FSK, while the other will go to the charter capital of

RusHydro. As a result, the state will not get direct stakes in generation companies; instead it will

receive shares in FSK and RusHydro in excess of what it could receive on a pro-rata basis.

The packages described above relate to UES’s generation and transmission assets only. MRSK

Holding (distribution), Far East Energy Holding, and InterRAO are distributed on a pro-rata basis

directly to all three groups of shareholders.

As a result of the second stage of the breakup, a typical UES minority shareholder will end up

with shares of 23 post-reform companies (the ―for‖ basket). (We regard a typical UES minority

shareholder as one who voted for the restructuring at the October 26 EGM, who did not

participate in the EGM, or who acquired shares after the EGM record date August 23, 2007.)

These companies include six thermal OGKs, 14 TGKs, RusHydro, FSK, MRSK Holding (which

will contain UES’s distribution assets), InterRAO (electricity importer and exporter plus several

power stations), and Far East Energy Holding (which will contain UES’s stakes in Far East and

isolated utilities). Those few minority shareholders who voted against the UES restructuring at

the EGM and who owned UES shares on June 6, 2008, will receive an ―against‖ basket, which

will contain shares of 26 entities and will differ from the ―for‖ basket as follows:

Figure 39: “For” and “against” baskets

Source: UES

Underlying

shares per

UES

common

Underlying

shares per

UES

preferred

Underlying

shares per

UES

common

Underlying

shares per

UES

preferred

MRSK Holding ** - 1 1 1 1

Far East Energy Holding ** - 1 1 1 1

FSK - 10.1056 9.2547 22.7734 20.8559

RusHydro HYDR 3.4532 3.1624 4.5042 4.1250

OGK-1 OGKA 0.9620 0.8810 0.3112 0.2850

OGK-2 OGKB 0.5008 0.4586 0.1620 0.1483

OGK-3 OGKC 0.4114 0.3768 0.1331 0.1219

OGK-4 OGKD 1.0274 0.9409 0.3323 0.3043

OGK-6 OGKF 0.5836 0.5345 0.1888 0.1729

TGK-1 TGKA 38.2332 35.0140 12.3666 11.3254

TGK-2 TGKB 12.9829 11.8897 4.1993 3.8458

TGK-3 (Mosenergo) MSNG 0.3360 0.3077 0.1087 0.0995

TGK-4 TGKD 15.8655 14.5296 5.1317 4.6996

TGK-6 TGKF 15.3259 14.0355 4.9572 4.5398

TGK-7 TGKG 0.3344 0.3062 0.1082 0.0991

TGK-8 TGKH 17.2625 15.8090 5.5836 5.1135

TGK-9 TGKI 67.3347 61.6651 21.7796 19.9457

TGK-10 * TGKJ 0.0089 0.0081 0.0029 0.0026

TGK-11 TGKK 6.1864 5.6655 2.0010 1.8325

TGK-12 (Kuzbassenergo) KZBE 0.6991 0.6402 0.2261 0.2071

TGK-13 (Yeniseyskaya TGK) TGKM 1.7233 1.5782 0.5574 0.5105

TGK-14 TGKN 9.7136 8.8957 3.1419 2.8773

InterRAO - 41.8643 38.3394 41.8643 38.3394

Centerenergoholding (Gazprom) ** - 0 0 1.0490 1.0490

Sibenergoholding (SUEK) ** - 0 0 0.9662 0.9662

Intergeneration (Norilsk Nickel) ** - 0 0 3.5169 3.5169

* If adjusted for planned share split, ratios would change to:

1.4710 1.3471 0.4758 0.4357

** UES prefs holders receive preferred shares in MRSK Holding, Far East Energy Holding,

Centerenergoholding, Sibenergoholding and Intergeneration

Voting FOR issue no. 1

on EGM agenda or not

participating

("FOR basket")

Voting AGAINST issue

no. 1 on EGM agenda

("AGAINST basket")

Company Ticker


The last trading day for UES shares on stock exchanges was June 6, 2008, which was also the

record date for the spinoffs. Those shareholders who owned UES shares as of 18:00 MSK on

this day receive one of the two baskets discussed above.

OTC trading of UES shares will continue until July 1, which is the date UES will conduct the

spinoffs and merge into FSK. Shareholders who acquire shares in UES after June 6 will have

their UES shares converted into FSK shares on July 1 at ratios of around 2.3 and 2.1 shares of

FSK per UES common and preferred share, respectively.

If a shareholder is recorded directly in UES’s register, he will receive all underlying shares by

July 4. If a shareholder owns UES shares through a depositary (nominee), he will receive

underlying shares sometime in mid-July (the exact date depends on the depositary).

Listing

Out of the 23 stocks a typical UES shareholder will receive, 19 are currently quoted on Russian

stock exchanges (5 OGKs, 13 TGKs and RusHydro). FSK and InterRAO shares will be listed in

July 2008, while MRSK Holding and Far East Energy Holding will be listed in September-

November 2008.

GDR holders

Issuance and withdrawal of depositary receipts on UES shares stopped on May 30, 2008.

Depositary receipt holders receive election packages presenting three options:

1. To receive depositary receipts on shares of underlying companies

2. To receive local shares of underlying companies

3. To cash out

In order to receive local shares or depositary receipts on local shares, investors need to present

certain information. Those depositary-receipt holders who fail to provide all the necessary

information will automatically receive cash proceeds from sales of shares. UES expects that local

shares of underlying companies and depositary receipts on such shares will be received by

depositary receipt holders by the end of July 2008, while the cash-out procedure may take three

to six months. UES expects the majority of underlying companies will launch depositary-receipt

programs before July. As an exception, shares of MRSK Holding and Far East Energy Holding

are likely to be received in September 2008, while depositary receipts for these shares will be

issued in December 2008 – January 2009. The delay is explained by the fact that these entities

will be established on July 1.


Figure 40: Timeline of corporate actions for local shares

Source: UES, RusHydro, FSK

Figure 41: Timeline of corporate actions for depositary receipts

Source: UES, RusHydro, InterRAO, FSK

3Q07 Jun 2008Aug 2008

EGM Record date

Aug 23

UES shares cancelled (UES ceases to exist)

Jul 1

Far East Energy Holdinglists in Russia

Sep

UES EGMon reorganization

Oct 26

Record date for UES breakup (holders of

local shares)

Jun 6

FSK share listing July

MRSK Holdingshare listing

Sep

RusHydrolists in Russia

Feb

Feb 2008 Apr 2008

UES shares excluded f rom RTS and MICEX Indices

Apr 30

May 2008

UES shares stop trading on stock exchanges

Jun 7

Futures on UES shareslast trading day - May 29

last delivery date - May 30

Jul 2008

Shares of underlying companiescompanies start trading

Jul 9

Non-trading period

Sep 2008

3Q07 Jun 2008 Dec 2008

EGM Record date

Aug 23

UES DRsexclusion f rom MCSI

indices

Depositary banks receive shares of

underlying companies

Jul 4

Far East Energy Holding

DRs issue

Dec

UES EGM on reorganization

Oct 26

Record date for UES breakup (DR

holders)

Jun 6

FSK, RusHydro, InterRAODRs issue

Jul

MRSK HoldingDRs issue

Dec

May 2008

DRs/cash-out election period

Jun 6 - Jul 7

DR issue books close, DRs cancelled

May 30

Jul 2008

DRs of underlying companies are received by

investors

Jul 7- Jul 21

UES DRs stop tradingJun 3

Cash-out periodJul 21

(1-3 months)

UES ceases to exist

Jul 1


Privatisation

The reform stipulates that the state give up control of companies in the competitive segment

(generation and supply companies) but maintain and increase ownership of transmission grids

(FSK), System Operator, and RusHydro. Initially distribution grids (as natural monopolies) were

to be kept under state control as well, but in 2006-2007 UES and state officials told the media

there was a possibility distribution companies would be privatised; this issue remains unresolved.

Furthermore, UES planned to divest all non-core segments, including repair and servicing

companies and engineering centers.


The privatisation of OGKs and TGKs has been on track since autumn 2006. UES transfers new

ownership in two ways: through additional share issues and through the sale of state-attributed

stakes.

Additional share issues are a primary source of financing for generation companies’ investment

programs. Additional issues are usually done either through a single block placement to a

strategic investor, or (rarely) as an SPO.

To date UES and its subsidiaries have sold or agreed to sell stakes in 23 generation companies.

The total value of the deals (including both additional share issues and sales of state-attributed

stakes) has reached USD 35 bn.


Figure 42: Generation company privatisation deals


Company Deal type Buyer Date

Additional

share

issue, post-

money, %

State-

attributed

stake, post-

money, %

Total

post-

money

stake, %

Deal

value,

USD mn

Priced

paid per

share,

USD

Implied

EV /

Installed

Capacity,

USD/kW

OGK-5 Additional share issue Porfolio investors Oct 06 14% 14% 459 0.090 320

OGK-3 Additional share issue & sale of state-attributed stake Norilsk Nickel Mar 07 38% 11% 49% 4 124 0.177 584

Yuznokuzbasskaya GRES (TGK-12) Sale of Kuzbassenergo stake Mechel Mar 07 93% 0 0.467 513

Zapadno-Sibirskaya CHP (TGK-12) Sale of Kuzbassenergo stake Evraz Mar 07 93% 0 0.403 407

Mosenergo (TGK-3) Additional share issue Gazprom Mar 07 29% 29% 2 345 0.204 596

TGK-5 Additional share issue IES May 07 27% 27% 455 0.00138 554

OGK-5 Sale of state-attributed stake Enel Jun 07 25% 25% 1 574 0.178 729

OGK-4 Additional share issue & sale of state-attributed stake E.ON Sep 07 22% 47% 69% 5 782 0.132 755

TGK-1 Additional share issue & sale of state-attributed stake Gazprom Sep 07 24% 29% 53% 2 854 0.00141 682

OGK-2 Additional share issue Gazprom, portfolio investors Oct 07 19% 19% 1 000 0.160 505

TGK-8 Additional share issue & sale of state-attributed stake Lukoil (via IFD Capital) Oct 07 33% 24% 57% 1 656 0.00141 568

Mosenergo (TGK-3) Sale of state-attributed stake Moscow government Nov 07 21% 21% 2 131 0.253 780

TGK-9 Additional share issue & sale of state-attributed stake IES Dec 07 27% 25% 52% 1 306 0.000322 657

Kuzbassenergo (TGK-12) Additional share issue SUEK, porfolio investors Dec 07 14% 14% 306 0.0306 434

OGK-6 Additional share issue & sale of state-attributed stake Gazprom Dec 07 17% 10% 27% 1 339 0.155 490

TGK-10 Additional share issue & sale of state-attributed stake Fortum Feb 08 47% 27% 75% 3 030 4.62 762

Novosibirskenergo Sale of UES stake Renaissance Capital Feb 08 14% 139 60.9 458

TGK-6 Additional share issue & sale of state-attributed stake IES & Prosperity Mar 08 31% 23% 55% 1 085 0.00106 439

TGK-2 Additional share issue & sale of state-attributed stake RWE & Sintez Mar 08 24% 25% 50% 776 0.00106 554

TGK-4 Additional share issue & sale of state-attributed stake Onexim (Norilsk Nickel) Apr 08 30% 23% 52% 1 183 0.00114 535

TGK-13 Additional share issue & sale of state-attributed stake SUEK, porfolio investors Apr 08 19% 14% 33% 469 0.00890 492

TGK-7 Additional share issue & sale of state-attributed stake IES Apr 08 13% 32% 45% 1 651 0.122 470

TGK-11 Sale of state-attributed stake E4 Group May 08 21% 21% 566 0.00172 421

Bashkirenergo Sale of UES stake Unitrade (IES) May 08 21% 464 1.997 426

TGK-14 Additional share issue & sale of state-attributed stakeEnergopromsbyt (Russian

Railways & ESN Group)Jun-08 43% 19% 62% 264 0.00031 368

Total 34 958


In looking at the prices paid for generation companies (measured by EV/capacity), we note the

following trends:

1. Portfolio investors usually paid a lower price than strategic investors. Public

offerings of generation companies were priced at USD 448/kW, which is 27%

below the average price paid by strategic investors of 569/kW.

2. Foreign strategic investors paid an average of USD 700/kW, 33% higher than the

USD 525/kW paid by Russian industrial investors.

Figure 43: EV/Capacity implied in deals

Source: Glitnir estimates

Forthcoming placements

There are three privatisation deals in the generation segment that are expected to be finished by

the end of the year. UES (or its heirs, FSK and RusHydro) will sell its state-attributed stake in

Kuzbassenergo (TGK-12). TGK-11 will float additional shares. The OGK-1 deal, which includes

both an additional share issue and the sale of a state-attributed stake, has not started yet.

Figure 44: Forthcoming placements


Post-reform ownership structure of the generation segment

After the UES breakup and privatisation is completed, the generation sector will still be directly

and indirectly dominated by the state. Generators controlled by the state (Rosenergoatom,

RusHydro, and others) together with those owned by the Gazprom account for 55% and 19% of

total installed capacity in the European and Siberian pricing zones, respectively.

OGK-5

OGK-3

Zapadno-Sibirskaya CHP

Mosenergo

TGK-5

OGK-5OGK-4

TGK-1

OGK-2

TGK-8

Mosenergo

TGK-9

TGK-12

OGK-6

TGK-10

Novosibirskenergo

TGK-6

TGK-2

TGK-4

TGK-7

TGK-11

Bashkirenergo

TGK-14

0

100

200

300

400

500

600

700

800

900

Jul 06 Oct 06 Jan 07 Apr 07 Aug 07 Nov 07 Feb 08 Jun 08 Sep 08

US

D/k

W

Yuzhnokuzbasskaya GRES

Company Deal type Possible buyer Date

Additional

share

issue, post-

money, %

State-

attributed

stake, post-

money, %

Total

post-

money

stake, %

Kuzbassenergo (TGK-12) Sale of state-attributed stake SUEK Jun-08 17% 17%

OGK-1Additional share issue & sale of

state-attributed stakeIES n/a 34% 41% 75%

TGK-11 Additional share issue E4 Group n/a 26% 26%


Figure 45: Ownership structure of generation assets by installed capacity



On the energy zone level, the state’s dominance is overwhelming: for instance, state-controlled

generators and Gazprom hold a total of 92% of installed capacity in the North-West energy zone,

68% in the South zone, 66% in the Volga zone, and 63% in the Center zone. However the

ownership structure has drastically changed from the one that existed before the reform, when

practically the entire sector was controlled by the state. We believe the privatisation measures

taken to date are enough to create the competitive environment necessary to promote

improvements in the efficiency of generation companies.

Figure 46: Ownership by energy zone, European Russia


Privatisation of distribution companies

There are no definite plans for the ultimate ownership structure of distribution companies.

Although the MRSKs will effectively remain under state control for at least several years, since

2006 UES has told various media sources that there is a chance privatisation will occur in 2010-

2015. We believe privatisation could promote improvements in efficiency and serve as an

additional trigger for the revaluation of distribution assets.

Ownership structure of distribution companies

UES received controlling stakes in the MRSKs upon their formation. After the UES breakup,

UES’s stakes in all distribution companies will be inherited by MRSK Holding, whose shareholder

structure will mirror that of UES.

Figure 47: Distribution company ownership


State32%

Gazprom24%

Norilsk Nickel & Onexim

8%

IES10%

Enel6%

E.On5%

RWE & Sintez1%

Fortum2%

Lukoil2%

Bashkirian ref ineries

4%

Other7%

State16%

Gazprom3%

SUEK15%

Norilsk Nickel & Onexim

4%Bazel42%

E.On3%

Group E410%

Other5% Energopromsbyt

2%

Region

Installed

electric

capacity

2007, MW State Gazprom

Norilsk

Nickel &

Onexim IES Enel E.On

RWE &

Sintez Fortum Lukoil

Bashkiria

refineries

Strategic

shareholder

to be

determined

Center 46 112 31.1% 31.9% 18.1% 3.7% 5.2% 3.8% 2.8% 3.4%

North-West 16 748 39.8% 52.5% 6.3% 1.4%

Volga 24 365 65.9% 34.1%

Urals 40 639 5.2% 14.4% 2.2% 12.4% 12.3% 13.3% 8.0% 12.7% 19.6%

South 15 635 39.2% 28.9% 8.3% 23.0% 0.7%

0% 20% 40% 60% 80% 100%

MRSK Center

MRSK South

MRSK North Caucasus

MRSK Center and Volga

MRSK North-West

MRSK Siberia

MRSK Urals

MRSK Volga

Moscow Unified Dist. Co.

Moscow City Dist. Co.

Lenenergo

Tyumenenergo

MRSK Holding Minorities


Supply company auctions

UES has sold 47 out of 57 supply companies to date, collecting USD 1 174 mn in gross

proceeds. The average deal price implies an EV/electricity sales of USD 6.6/MWh and an

EV/revenues of USD 0.152.

Figure 48: Supply company auctions


UES (or its heir, Far East Energy Holding) has yet to auction six supply companies, including

Moscow and Petersburg Supply Companies.

Company

RTS

ticker

UES

stake

auctioned

Price

paid at

auction,

USD mn

Premium

over

starting

price

Implied

EV/

Electricity

sales,

USD/MWh

Implied

EV/

Revenues

Yaroslavl Supply Co. 47% 16 133% 6.13 0.135

Kuban Supply Co. 49% 33 0% 5.98 0.251

Nizhnovgorod Supply Co. NNSB 49% 79 173% 16.45 0.323

Sverdlov Supply Co. SVSB 49% 45 0% 4.58 0.106

Kuzbass Supply Co. KZSB 49% 44 0% 3.46 0.254

Orenburg Supply Co. 100% 43 0% 1.91 0.043

Belgorod Supply Co. BLSB 49% 36 268% 9.09 0.193

Vologda Supply Co. VOSB 49% 10 0% 3.96 0.277

Kurgan Supply Co. 49% 3 0% 2.01 0.144

Karelia Supply Co. 100% 14 0% 5.35 0.156

Voronezh Supply Co. VRSB 49% 12 0% 5.26 0.122

Tver Supply Co. TVSB 49% 22 0% 13.59 0.224

Vladimir Supply Co. VDSB 49% 12 2% 6.32 0.118

Lipetsk Supply Co. LPSB 49% 20 101% 6.27 0.150

Tula Supply Co. TLSB 49% 20 20% 5.03 0.100

Buryat Supply Co. BUSB 47% 8 0% 7.68 0.129

Mari Supply Co. MISB 64% 6 1% 5.59 0.097

Tomsk Supply Co. TOSB 52% 10 1% 4.83 0.112

Omsk Supply Co. OMSB 49% 13 2% 4.23 0.093

Khakas Supply Co. 100% 9 1% 0.60 0.056

Udmurtia Supply Co. UDSB 49% 21 3% 6.27 0.153

Kirov Supply Co. KISB 48% 12 1% 3.21 0.061

Sibirenergo 14% 5 0% 3.51 n/a

Novgorod Supply Co. NGSB 49% 5 4% 6.05 0.106

Kostroma Supply Co. KTSB 49% 6 0% 9.42 0.152

Ryazan Supply Co. RZSB 49% 27 50% 10.24 0.236

Chuvashia Supply Co. 100% 27 12% 5.50 0.123

Mordovia Supply Co. MRSB 53% 8 52% 6.22 0.105

Kursk Supply Co. KUSB 49% 11 0% 9.06 0.157

Chita Supply Co. CHSB 49% 9 0% 2.82 0.066

Smolensk Supply Co. SMSB 51% 15 67% 9.19 0.135

Astrakhan Supply Co. ASSB 49% 15 0% 13.13 0.326

Kola Supply Co. KOSB 49% 19 0% 3.27 0.112

Samaraenergo Supply Co. SAGO 55% 86 0% 6.94 0.142

Ulyanovskenergo Supply Co. ULEN 49% 5 0% 14.87 0.353

Volgograd Supply Co. VGSB 49% 24 0% 7.94 0.158

Penza Supply Co. PZSB 49% 19 88% 12.47 0.174

Orel Supply Co. ORSB 49% 5 0% 9.16 0.166

Ivanovo Supply Co. IVSB 50% 16 0% 8.20 0.151

Komi Supply Co. 50% 11 39% 5.58 0.194

Stavropol Supply Co. STSB 55% 20 46% 6.05 0.132

Bryansk Supply Co. BNSB 49% 11 39% 9.88 0.182

Arkhangelsk Supply Co. ARSB 49% 7 1% 1.91 0.053

Rostov Supply Co. RTSB 48% 21 5% 3.68 0.085

Tyumen Supply Co. 100% 241 57% 1.40 0.041

Kaluga Supply Co. KLSB 52% 19 0% 12.61 0.253

Perm Supply Co. PMSB 49% 53 32% 4.58 0.102

Total/Average 1 174 6.64 0.152

WA 7.04 0.129

Median 6.05 0.139


Figure 49: Forthcoming supply company auctions


The switch to market-based pricing

Pre-reform: Cost-based regulation

Until recently the state had full control over the operational activity of power companies. A special

government body, the Federal Service for Tariffs (FST), determined both production volumes and

tariffs for every utility company in the country.

Before the reform, the FST set tariffs for each AO-energo and each stand-alone GRES. For the

AO-energos the tariff included a total payment for the entire production chain, from generation to

distribution and supply. For GRESs the payment covered only electricity generation. UES also

charged a subscription fee from its subsidiaries to finance expenses and redistribute income

within the group.

The tariff system for all the utility companies was based on the ―cost-plus‖ approach: the

companies were compensated for planned expenses for the next year and left with a margin

close to zero. If a particular company needed funds for repairs or the construction of new power

blocks (and such cases were rare), the company’s tariff was raised for one or several years in

order to finance capex; after the capex was paid, the tariff dropped back to the previous level,

generally maintaining zero cash flow.

The price of gas (the main cost driver for most utilities) was also regulated by the FST, and was

indexed with the expected inflation rate for the next year. Based on expected fuel prices and

costs, the government set tariffs for utility companies that usually corresponded with the

expected inflation rate.

Under the cost-plus system, any cost cuts resulted in a corresponding cut in the tariff the

following year, leaving the companies with low profitability. The companies thus had virtually no

incentive to improve efficiency; instead they were prompted to inflate costs. Those companies

that were in better relations with the regulator generally managed to negotiate sharper hikes in

costs and thus tariffs, which resulted in significant deviation of regulated tariffs across

companies.

Company

RTS

ticker

UES stake

to be

auctioned

Expected

date

Starting

price,

USD mn

Implied

EV/

Electricity

sales,

USD/MWh

Implied

EV/

Revenues

Via auctions

Petersburg Supply Co. PBSB 49% Jun 08 211.9 14.3 0.345

Saratovenergo Supply Co. SARE 48% Jun 08 36.0 8.7 0.184

Moscow Supply Co. MSSB 51% n/a 475.3 14.1 0.25

Chelyabinsk Supply Co. CLSB 49% n/a n/a n/a n/a

Via ISTRA trading system

Pskov Supply Co. 100% n/a 16.1 10.2 0.143

Tambov Supply Co. TASB 49% n/a 13.1 8.1 0.131


Figure 50: Regulated electricity tariff, 2008e


Figure 51: Regulated capacity tariff, 2008e


In the early 2000s inflation was one of the government’s biggest concerns, as tariffs for services

provided by natural monopolies were considered one of the core drivers of inflation. The

government’s intention to enforce improvements in efficiency coupled with its desire to keep

tariffs low led to the introduction of ―inflation-minus‖ regulation, which required that electricity

tariffs be indexed at a rate below inflation. The government supposed that companies had the

potential to cut costs and that the pressure of fuel prices (which outpaced electricity tariffs) would

promote improvements in efficiency.

0

5

10

15

20

25

30

35

40

45

50

TG

K-2

TG

K-9

OG

K-6

OG

K-3

TG

K-7

TG

K-8

TG

K-6

OG

K-1

TG

K-4

OG

K-5

TG

K-5

TG

K-3

OG

K-2

TG

K-1

1

TG

K-1

0

TG

K-1

4

OG

K-4

No

vo

sib

irske

ne

rgo

TG

K-1

2

TG

K-1

TG

K-1

3

Hyd

roO

GK

Irku

tske

ne

rgo

Kra

sn

oya

rsk G

ES

US

D/M

Wh

0

10

20

30

40

50

60

70

80

TG

K-9

TG

K-1

0

No

vo

sib

irske

ne

rgo

Hyd

roO

GK

TG

K-1

1

TG

K-4

TG

K-3

OG

K-6

OG

K-5

TG

K-1

4

TG

K-1

2

OG

K-1

OG

K-4

TG

K-5

OG

K-3

TG

K-1

3

TG

K-6

TG

K-7

OG

K-2

TG

K-8

TG

K-1

Irku

tske

ne

rgo

TG

K-2

Kra

sn

oya

rsk G

ES

US

D/k

W p

er

ye

ar


Figure 52: Average growth of power tariffs vs. inflation

Source: Rosstat, UES

However, inflation-minus regulation had only a marginal impact on improving efficiency itself, as

it failed to provide any real economic incentives for cutting costs. Instead, utility companies

generated even less cash flow, and many of them began posting net losses, which increased

each year. Utility companies have not made any sizable profit under cost-based tariff regulation

for years and therefore have probably been the biggest victims of the fight against inflation.

Figure 53: UES profitability since 2001

Source: UES

The cost-plus system probably could have existed for several more years had the capacity deficit

and unreliable power supply not been such big problems. The sector’s huge capex needs, which

were impossible to finance through external sources, forced the government to develop a plan to

change the regulatory landscape in order to provide a fair return on invested capital.

Post-reform: The road to the free market and fair-return regulation

The restructuring process resulted in the breaking up of AO-energos into a number of smaller

companies, each of which represented a separate segment: generation, transmission,

distribution, supply, or non-core activity. The reform stipulates that utility companies operating in

competitive segments (generation and supply) are to sell on liberalised markets (the wholesale

market for generators, and the retail market for supply companies), while tariffs of those

operating in naturally monopolistic segments (distribution and transmission grids) are to continue

to be regulated by the government. The reform also specifies that the regulation of natural

monopolies must be changed to provide a fair return on invested capital.

Generation: The road to the free market

According to current legislation, generators in Russia receive two separate revenue flows:

Electricity sales = Volume of electricity actually supplied (MWh) x Electricity tariff

(RUB/MWh)

Capacity sales = Installed capacity x Capacity payment (RUB/kW/month). These sales

represent compensation for the generator’s ability to provide a certain volume of

electric capacity (MW) in a certain technological condition. Capacity payments are

ultimately aimed at ensuring the generator’s ability to handle consumption peaks,

which is a key element in determining the reliability of the power system as a whole.

The FST determines separate tariffs for electricity and for capacity. This two-tariff system is

designed in such a way that the electricity tariff covers only variable costs (fuel), while the

payment for capacity covers fixed costs (such as operating and maintenance expenses) and the

cost of capital.

0%

5%

10%

15%

20%

25%

30%

2001 2002 2003 2004 2005 2006 2007

Average retail electricity tarif f growth, %

Inf lation, %

0%

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4%

6%

8%

10%

12%

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2001 2002 2003 2004 2005 2006

US

D b

n

Revenues, USD bn Net income margin, % ROE, %


Capacity payments are an important contribution to revenues and currently make up 31-78% of

generation companies’ top lines.

Figure 54: Capacity payment as % of total revenues, 2006

Source: UES

The reform stipulates the liberalisation of both the electricity and capacity markets. So far,

however, the government has only adopted the necessary legislation to liberalise the electricity

market, while no action has been taken in regards to the capacity market. As a result, a portion of

electricity is currently traded at unregulated prices, while capacity payments are still 100%

regulated.

Electricity market

The first attempt to liberalise the electricity market was in 2006, when the government introduced

the so-called ―5-15‖ market, according to rules of which generators had the right to sell up to 5%

of their output and consumers were allowed to buy up to 15% of their consumption at

unregulated prices. However, as consumers were given the choice to buy electricity at either the

regulated or unregulated tariff—essentially an arbitrage option—the market price of electricity

was effectively capped by the regulated tariff.

The New Wholesale Electricity and Capacity Market (NOREM) established by Government

Decree No. 529 dated August 31, 2006 and launched in September 2006 is the target model for

the electricity market and will remain in effect for the foreseeable future. It consists of the

following three segments:

Bilateral contracts between sellers (generators) and buyers (supply companies and

large consumers). The majority of electricity is sold through bilateral contracts.

Day-ahead market. This is effectively an electronic spot market organized by the

Administrator of Trading Systems (ATS).

Balancing market. This is a real-time system where deviations from the hourly

volumes of production planned on the day-ahead market are traded. The balancing

market typically covers 3-5% of total power consumption.

In the future UES expects that other instruments such as derivatives will emerge to complement

these three segments.

Bilateral contracts

With the launch of NOREM, generators signed the first regulated bilateral contracts for 100% of

their expected production through the end of 2006. Planned volumes as well as prices of

regulated contracts are set by the FST. Regulated contracts are financial in nature: a generator is

obliged to sell a certain volume of electricity at a regulated tariff. The generator is given the

option of either producing this volume in its own generation facilities or buying it from other

producers (from the market) and reselling it to customers in order to fulfil its obligations in

electricity delivery.

The electricity market is being liberalised (deregulated) through the gradual reduction of the

amount of electricity sold through regulated contracts. The pace of this reduction was set by

Government Decree No. 205 dated April 7, 2007, which states that electricity sold at free prices

will reach 100% of sales volume by January 1, 2011, excluding volumes sold to the population.

Currently 15-20% of electricity trades at unregulated prices, and this amount will increase to 25-

30% beginning July 1, 2008.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Nuclear Hydro CCGT CHP GRES


Figure 55: Electricity market liberalisation schedule


Any electricity a generator produces in excess of regulated contracts may be sold at unregulated

prices either through unregulated bilateral contracts or on the day-ahead market. The new rules

also stipulate, however, that power blocks constructed after 2007 (i.e. in 2008 and beyond) are

allowed to sell 100% of production volumes at unregulated prices.

Day-ahead market

The day-ahead market is an electronic spot market organized by the ATS. Buyers (supply

companies and large industrial consumers) submit bids of their expected hourly consumption for

the next day, and sellers (generators) submit offers of their expected hourly generation. Day-

ahead trading is based on the marginal generator principle: the ATS determines a uniform

equilibrium (―clearing‖) price equal to the offer price of the most efficient generator that covers

marginal consumption. Offers submitted to the system must correspond to the generators’ actual

variable costs per megawatt hour produced. The government’s antimonopoly service is entitled

to verify offers from the marginal generator; if it finds the marginal generator has overstated its

variable costs (and correspondingly, its offer price), it may impose penalties or other prohibitive

measures.

The actual dynamics of the clearing price on the day-ahead market indicates that this market has

several traits of a normal liberalised electricity market, such as intraday and seasonal effects.

5%

25%30%

50%

60%

80%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

10%15%

100%

Excluding volumes soldto households


Figure 56: Hourly electricity prices and volumes on April 29, 2008


Source: ATS Source: ATS

Figure 57: Seasonal dynamics


Source: ATS Source Source: ATS

0

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Russia is divided into two pricing zones: European Russia and Siberia. This division is due to

constraints in transmission capacity that prevent the free flow of electricity between the zones.

The ATS determines an equilibrium price for each zone separately.

European Russia can be further divided into five energy zones, which are characterized by

limited inter-connection capacity: North West, Center, Urals, Volga, and South. However, these

limitations are much less serious than those between the pricing zones.

There are also ―non-pricing‖ zones, which lack the ability to transmit electricity to the rest of the

power system. These non-pricing zones include Komi and Arkhangelsk in the North West, and

the Amur, Primorsk, Khabarovsk, South Yakutia, Sakha, and Jewish Autonomous regions in the

Far East. Furthermore, some regions (Norilsk, Kalmykiya, Magadan, Chukotka, Kamchatka,

Sakhalin, and Kaliningrad) are completely isolated from one another and from the rest of the grid.

As there is no way to introduce the market in non-pricing zones and isolated regions, tariffs for

companies located in these zones and regions will remain regulated for the foreseeable future.

Figure 58: Pricing & energy zones

Source: UES

The pricing zones are characterized by different structures among their generation assets:

European Russia is dominated by gas-fired generators, while Siberia is heavily influenced by

hydroelectric and coal-fired plants. This structure can be explained by geographic conditions

(Siberia is rich in water resources and coal), as well as by infrastructure constraints (most

regions in Siberia have no or limited gas network).

Figure 59: Generation by fuel type, 2007



Thermal gas58.1%

Thermal coal7.7%

Thermal fuel oil

1.0%

Thermal other0.1%

Hydro9.8%

Nuclear23.2%

Thermal gas4.0%

Thermal coal

50.6%

Thermal fuel oil0.5%

Hydro 45.0%


The supply-and-demand relationship and structure of generation assets located in a certain

pricing zone determines the dynamics of the market price in that zone. For instance in European

Russia, where reserve margin is tight and most power plants are fuelled by expensive gas,

average electricity prices are higher (USD 22.7/MWh in 2007), while in Siberia the average price

of electricity is lower (USD 11.4/MWh in 2007) due to abundant hydroelectric capacities, access

to cheap coal, and a higher reserve margin.

Figure 60: Electricity price dynamics


Source: ATS, Glitnir calculations Source: ATS, Glitnir calculations

Capacity market

The government is currently discussing the rules for the future capacity market. Most recently

state officials and UES said these rules are to be approved in July 2008. However, discussion of

the new capacity market dates back almost two years and its introduction has already been

postponed several times. There is a chance the introduction of the new rules could be delayed

further.

So far, no official documents on the projected capacity market have been released, nor has the

timetable or pace of liberalisation for the capacity market been announced. The reform

legislature states the capacity market should be liberalised at the same time and pace as the

electricity market, but whereas 15% of electricity volumes are currently sold at free prices (and

this share will expand to 25% on July 1, 2008), we see virtually no progress in the liberalisation of

the capacity market.

The only indication of the form the future capacity market may take comes from materials that

UES has released in various presentations since 2006. In our view these materials provided

more questions than answers regarding the key features of the capacity market. Furthermore, we

believe the final official rules may differ materially from those presented by UES. For now we

believe investors have no other option but to guess what the rules of the capacity market will

ultimately be, but for those curious about UES’s proposals on the capacity market we have listed

them below.

UES proposed that the capacity market would begin to be gradually liberalised in 2008, and the

pace of this liberalisation would equal that of the electricity market, meaning that starting in 2009,

tariffs for a maximum of 70% of both electricity and capacity would be regulated. As in the case

of the electricity market, existing capacity in excess of regulated volumes and new capacity

constructed after 2007 would be traded through market-based mechanisms.

Capacity is to be auctioned four years in advance of delivery. For instance, the first auction, to be

held in 2008, is to relate to capacity delivered in 2012. Auctions for capacity to be delivered in

2009-2011 are considered transitory, and will have special rules.

The auctions (also called ―competitive selection of capacity‖) are planned as follows:

1. The territory is divided into capacity free-flow zones. A free-flow zone is a zone in

which there are practically no technical limitations on the transfer of electricity from any

point in the zone to another. These zones are even smaller than pricing and energy

zones.

0

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16.419.7

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4.65.9

20.1

16.9


2. For each free-flow zone, the operator determines the volume of capacity required to

cover the expected consumption peak and the required technical parameters of

capacity.

3. Generators submit price offers.

4. The generators who submit the lowest offers and provide the required volume of

capacity in each free-flow zone with the required technical parameters are selected.

Selected generators are to have two options:

1. To sell both capacity and electricity at free prices

2. To receive a guaranteed (regulated) capacity payment for 10 years. (In this case, the

generator would be required to sell electricity at regulated tariffs as well.)

Generators that are not selected would have no option for guaranteed capacity payment and

would try to sell capacity on the free market.

UES expects the second option would typically be attractive only to those inefficient generators

not able to sell capacity on the free market.

Also, UES expects generators would be able to sign bilateral contracts on the delivery of both

electricity and capacity, meaning these contracts would have a single price.

Electricity consumers would be obliged to pay for their actual peaks in consumption.

Presentations made by UES showed that transitory auctions (for capacity to be delivered in

2008-2011) will have several limitations, including caps on the offer price that a generator can

submit to the auction (price caps can equal the regulated capacity tariff).

If UES’s expectations prove correct, transitory auctions would effectively have no market-based

pricing, meaning the capacity market would be liberalised no sooner than 2012.

Hydroelectric regulation

The current legislative environment envisages several special conditions regarding hydroelectric

plants:

1. Hydroelectric plants are price-takers in the day-ahead market, meaning they can

submit only a price offer of zero to the trading system.

2. Hydroelectric plants are subject to a special tax on the use of natural water resources.

Currently the water tax is marginal, at USD 0.4 /MWh. Hydroelectric plants, which bear no fuel

costs, receive the same price for electricity as fuel-fired generators in the liberalised market,

effectively earning windfall profits. We consider it reasonable to expect that when the electricity

market is liberalised and the huge profits earned by hydroelectric plants become evident, the

government will tax these profits, leaving shareholders with a more or less fair economic return

on invested capital.

Heat regulation

While heat plays a minor role for OGKs, it is an important contributor to the top line of TGKs and

vertically integrated utilities.

Figure 61: Share of heat in total revenues, 2007


0%

10%

20%

30%

40%

50%

60%

70%

TG

K-1

4TG

K-9

TG

K-4

TG

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TG

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TG

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TG

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renerg

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nerg

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nerg

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2O

GK

-6O

GK

-5O

GK

-4O

GK

-3O

GK

-2O

GK

-1

Share of heat in total revenues, 2007


Heat consumption

Heat consumption in Russia generally moves in line with GDP. Since 1998, total heat

consumption in Russia has shown steady growth, with a CAGR of 2.1%.

Figure 62: GDP growth vs. heat consumption

Source: Rosstat, Glitnir estimates

Sector structure

The heat sector is composed of TGKs, which inherited the heat assets of AO-energos

(cogeneration power plants, which produce electricity and heat, boilers, and heat pipelines), and

local boilers, which are controlled by regional authorities and private owners.

Figure 63: Heat sales, 2006

Source: Rosstat

Tariffs for each segment (heat generation, transportation, and supply) are regulated by regional

energy commissions, special tariff-setting bodies of the regional authorities. Regulation is based

on the cost-plus approach and depends heavily on the relationship between TGK executives and

owners and the local authorities. Most local authorities aim to keep tariffs at the lowest possible

level, so the profitability of a TGK’s heat business depends on how well the company deals with

local officials.

1.4% -5.3%6.4%

10.0%

5.1%4.7%

7.3%

7.2%

6.4%

7.4%

8.1%

-4.8%-2.9%

1.6%3.2% 1.8%

10.3%3.4% 0.9%

0.2% 2.8%-4.4%

-10%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

1996 1998 2000 2002 2004 2006

Cumulative GDP growth, % Heat output growth cumulative

Electricpower plants

44.1%

Boilers50.4%

Other5.5%


Figure 64: Heat tariff and heat operating profit margin, 2006


The government has not announced any plans to change the regulation of the heat segment, but

it is becoming evident to local officials that regulation of the heat segment needs to be changed

for the same reasons as in the electricity segment: the need for investments to overhaul outdated

equipment and the need to improve efficiency. However, the timetable for these changes

remains unclear.

Distribution: The switch to RAB

Before the reform, AO-energos received compensation for power distribution services as a part

of the overall industry tariff. Currently each spun-off distribution company receives a separate

tariff for electricity distribution. These tariffs are calculated using the cost-plus approach, meaning

the tariff covers operating costs and provides additional cash to finance capex. Each distribution

company’s profit is typically a function of its capex needs the higher the need to invest in a

particular region, the more favourable the tariff.

The cost-plus tariff system does not provide any stimulus for distribution companies to improve

efficiency, nor does it provide investors with sufficient return on invested capital. Under such a

tariff system, any savings the distribution companies manage to make are met with a

corresponding reduction in the company’s tariff.

On June 18, 2008, the Russian government signed Decree No. 459, which enables the switch

from the cost-plus tariff system to the regulatory asset base (RAB) model, a return-based

approach that is used in various forms in the regulation of power grid assets in many countries

around the world. The decree sets the general principles of the new regulatory system, which

include a fair market return on invested capital for investors and mechanisms to stimulate

improvements in efficiency among distribution companies.

The government set a 3-month deadline for the FST to develop the exact methodology for tariff

setting in accordance with the RAB approach. However, the decree itself provides some insights

on how the RAB system will work in Russia:

Under the RAB system, tariffs are set on the basis of required revenue, which is

determined by a regulator on a long-term basis. Required revenue is subject to annual

adjustments to account for differences between projected long-term regulation

parameters and actual numbers. Required revenue provides:

o Defrayal of operating expenses

o Defrayal of depreciation of invested capital (or RAB)

o Return on invested capital (or RAB)

-30%

-20%

-10%

0%

10%

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30%

40%

0

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OG

K-5

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zb

asse

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US

D/G

Ca

l

Heat tariff, 2006 (USD/Gcal) EBIT margin, heat, 2006 (%)


Invested capital (RAB) for regulatory purposes is determined in accordance with rules

to be adopted by the FST. The initial size of invested capital is set on the basis of

independent appraisal, and should correlate with the replacement value of assets and

with their physical and economic depreciation. Size of invested capital is adjusted

annually to account for investments in fixed assets and working capital (which

increases RAB) and depreciation of assets (which decreases RAB).

Invested capital for RAB purposes is accounted for separately from financial and tax

accounting.

Savings resulting from the reduction of operating expenses and losses in grid (i.e. the

difference between regulated and actual values of expenses and losses) are kept in

revenues for five years.

Regulated revenue can be shifted by the regulator from one year to another to smooth

the transition to the RAB method.

According to the statements of government officials and UES, RAB regulation will begin for

between four and six pilot distribution companies on July 1, 2008, while the remaining distribution

companies will switch to the new regulation in 2009-2010. However according to the decree,

tariffs set for 2008 will not be changed, which effectively means that a switch to RAB-based

tariffs will happen no sooner than 2009.

Connection fees

The RAB system should provide a significant boost to cash flow for distribution companies in two

or three years, but these companies face urgent capex needs already. As a temporary means of

financing the construction of new power grids, the government has introduced a connection fee,

which is charged directly to new consumers when connecting to the grid. This connection fee is

expected to remain in effect until the RAB system is introduced, at which point it will be

discontinued.

The connection fee serves as an important source of revenue for distribution companies and is a

substantial driver of short-term profitability. The amount of the fee varies dramatically across

Russia’s regions, peaking at USD 940 per kW for Lenenergo and USD 1 680 per kW for Moscow

City Distribution Company.

According to Decree No. 459, new assets financed by connection fees will not be included in

invested capital (RAB) for tariff-setting purposes. Therefore connection fees have limited

influence on the fair value of distribution companies, as their shareholders will not receive a

return on assets that were financed through connection fees.

Transmission grid regulation

Current regulation of transmission grids is generally the same as that of distribution grids.

Transmission companies receive a tariff for electricity transmission services based on the cost-

plus approach (i.e., companies’ revenues only cover current operating costs and maintenance

capex needs).

In May 2008, Deputy CEO of FSK Alexander Chistyakov told analysts that regulation of FSK is

expected to be switched to the RAB approach in 2009-2011. He also mentioned that the effect

this switch will have has already been incorporated into Ministry for Economic Development and

Trade forecasts. Another indication that such a switch is likely is the methodology used by UES’s

independent appraiser to evaluate transmission companies for their consolidation into FSK. The

appraiser assumed transmission companies would switch to a RAB-like system beginning in

2012.

Far East and isolated regulation

Tariffs for Far East and isolated energy companies will continue to be fully regulated by the state

for at least the next several years. However, in presentations in 2006 and 2007 UES stated the

importance of changing the current cost-based tariff system to one that would stimulate

investments in the modernization and improvements in the efficiency of Far East and isolated

utilities. Furthermore, the company has considered ways of implementing these changes without

sharply increasing the final price of electricity paid by consumers (namely, direct subsidies to

utilities from the state budget). UES has also voiced the possibility of introducing a competitive

market in the Far East region within five years, after eliminating the technological constraints on

establishing such a market.


Reform of independent energy companies

Like any other utility company in Russia, independent vertically integrated utility companies

(Bashkirenergo, Irkutskenergo, Tatenergo, and Novosibirskenergo) are subject to electricity

legislation rulings, including but not limited to the separation of competitive from monopolistic

activity. Thus Bashkirenergo, Novosibirskenergo, Irkutskenergo, and Tatenergo have created

100%-owned subsidiaries to which they have transferred their distribution and transmission

assets.

The generation assets of independent energy companies are players on the electricity market

and receive the same benefits from the liberalisation of the electricity market as OGKs and

TGKs.

Independent energy companies’ distribution and transmission assets are regulated by the same

laws as MRSKs and FSK, respectively; therefore we can expect segment-wide regulatory

changes (such as the introduction of a RAB-based tariff system) to impact these assets as well.


Fuel supply

Thermal power plants that burn non-renewable natural resources such as gas, coal, and fuel oil

generate 66% of electricity in Russia.

The main fuel used by thermal generators in Russia is gas.

Figure 65: Fuel balance, Russia total, 2006


The cheapest fuel in 2007 was gas. Due to their proximity to coal deposits, generators in Siberia

paid significantly lower effective coal prices than generators in European Russia.

Figure 66: Prices by fuel type, 2007


Gas

Utility companies receive gas from Gazprom, as well as from independent gas producers (such

as Novatek and Itera) and integrated oil and gas companies. Russia has enough gas reserves to

satisfy current gas consumption for at least 74 years.

Figure 67: Gas production by producer, 2007


Gazprom is the dominant supplier of gas in Russia, and therefore its domestic tariffs are

regulated by the FST. Gazprom supplies gas on the basis of bilateral contracts with consumers.

The length of these contracts is typically one to three years.

Gazprom sets a limit on the amount of gas that can be sold at regulated tariffs for each

consumer. If a generator consumes gas in excess of this limit, Gazprom charges a penalty,

which increases the effective price of gas consumed above the limit by up to 80%.

Gas70%

Coal26%

Fuel oil3%Other

1%

168

55 4934

020406080

100120140160180

Fuel oil Coal (European Russia)

Gas Coal (Siberia)

US

D/t

fe

Gazprom84%

Novatek4%Rosnef t

3%Lukoil2%

TNK-BP1%

Other4%

Surgutnef tegaz

2%


The FST determines a separate gas tariff for each region of the Russian Federation. Gas tariffs

vary across regions depending on the distance between the region and Gazprom’s main gas

fields.

Figure 68: Gas tariffs by region, 2008

Source: Federal Service for Tariffs

In 2006 the government decided to gradually increase domestic gas tariffs with the aim of

reaching net back parity of domestic supply with exports to Europe. (Net back parity implies that

Gazprom’s sales to Europe have the same profitability as its sales to domestic consumers.) The

government-approved timetable for this process implies domestic gas tariffs will reach net back

parity by 2011, the same year by which 100% of electricity will be sold at free prices.

Independent producers and major Russian oil companies supply gas on the basis of unregulated

contracts, meaning the price and size of these contracts is negotiated directly between

consumers and producers case by case. Typically gas prices of independent producers and

major oil companies follow the dynamics of those charged by Gazprom, but in each case their

absolute effective value is determined by their distance from the gas field (i.e. transportation

costs) and type of gas (associated gas being the cheapest).

The existing gas transportation network supplies gas to most of the European part of Russia,

with the exception of the Arkhangelsk and Komi regions in the north. There are also separate

cases in which the capacity of the gas transportation network does not meet the needs of power

plants. One example is Konakovskaya GRES (OGK-5), located in the Tver region. Due to

insufficient capacity of the gas pipeline, in the last several years the plant’s load factor has not

exceeded 40%.

The gas network in Siberia is poorly developed.

Figure 69: Penetration of gas transportation network

Source: Gazprom

Region USD/mcm

Yamalo-Nenets 40.1

Khantymansiisk 48.2

Tyumen 56.9

Astrakhan, Orenburg, Komi 61.7

Kurgan, Perm, Udmurtia 64.0

Arkhangelsk, Bashkiria, Sverdlovsk, Tomsk 65.4

Kirov, Chelyabinsk, Mary-El, Tatarstan, Chuvashia, Kalmykia, Omsk 67.3

Vologda, Nizhny Novgorod, Yaroslavl, Mordovia, Penza, Samara, Ulyanovsk,

Novosibirsk68.0

Vladimir, Ivanovo, Kostroma, Lipetsk, Tambov, Tver, Saratov, Karelia,

Leningrad region, St. Petersburg, Novgorod71.2

Belgorod, Bryansk, Volgograd, Voronezh, Kaluga, Kursk, Moscow, Moscow

region, Orel, Ryazan, Smolensk, Tula, Pskov, Altai, Kemerovo73.5

Rostov 76.1

Adygea, Dagestan, Ingushetia, Kabardino-Balkaria, Karachayevo-Cherkessia,

North Ossetia, Chechnya, Krasnodar, Stavropol76.7

Kaliningrad 86.2


Coal

Coal-fired generation accounts for 26% of total power generation in Russia. The main coal

deposits are located in the Kuzbass (West Siberia) and Pechora (North-East Russia) regions.

Russia is abundant in coal; proven reserves can handle current domestic consumption for over

400 years.

The major suppliers of thermal coal in Russia are SUEK, Kuzbassrazrezugol, Yuzkuzbassugol

(Evraz), and South Kuzbass Coal (Mechel), which together control about 60% of thermal coal

production.

Figure 70: Thermal market, by market share

Source: Company data, AK&M, MetalExpert, Central Dispatching Department, Glitnir estimates

Coal is freely traded and the industry is rather competitive. The price of coal is made up of two

major components: the FCA price (at the place of mining) and the cost of transportation. Cost of

transportation is a substantial component of the total effective price of coal paid by a generator

and can reach up to 50-60% of the final price paid by the consumer. Transportation costs

significantly reduce the economic availability of coal across distances.

Fuel oil

Fuel oil is used as a reserve fuel in most power stations; its share in the fuel mix of an average

power station rarely exceeds 3-5%. Fuel oil is commonly supplied by oil refineries owned by

large Russian oil and gas companies. Domestic fuel oil prices are not regulated and generally

follow the world prices of oil products. Because Gazprom sets limitations on consumption for

gas-fired generators, the latter have no other choice than to burn expensive fuel oil during

unexpected power consumption. Sharp spikes in demand spurred by speculator activity can lead

fuel oil prices to skyrocket during the cold season.

A new government strategy on fuel consumption

Fuel consumption has risen to utmost importance in Russia. Pushed by the president, the

government developed the General Scheme for Power Facility Allocation, a massive document

that envisages the size, technical parameters, fuel type, and location of every new power block to

be constructed through 2020. The scheme is based on the state’s views on growth in power

consumption across the regions as well as its fuel usage strategy.

The government set the following priorities in the scheme:

In European Russia, to maximize the development of nuclear and hydro-accumulating

power stations (GAESs) and the modernization of gas-fired power stations

In Siberia, to construct hydroelectric and coal-fired power plants

In the Far East, to develop hydroelectric and coal-fired power plants as well as power

plants fuelled by gas from Sakhalin

Overall the scheme envisages growth in average fuel consumption from 295 mn tfe in 2006 to

428 mn tfe in 2020, an increase of 45%, compared with an increase in power consumption of

76% over the same period. The scheme thus shows that as a result of modernized generation

assets, the average fuel burn rate will fall 15%, from 336 gfe/kWh in 2006 to 286 gfe/kWh in

2020, with a corresponding change in the efficiency ratio from 36.7% to 43.4%.

SUEK36%

Mechel6%

SDS-Ugol

Holding

Company2%

Evraz Group

2%

Lutek2%

Other37%

Kuzbassrazrezugol16%


Figure 71: Fuel consumption vs. power consumption growth


Figure 72: Change in average fuel burn rate, government forecast


The scheme also envisages a change towards a higher share of coal in the fuel balance, from

25% in 2006 to 39% in 2020.

Figure 73: Government fuel mix forecast


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Valuation

In this section we discuss the assumptions and methods we used to derive target values for the

43 listed utility companies and the four companies that are expected to list their shares by the

end of 2008.

Macro assumptions

We used the following assumptions for macroeconomic variables and commodity prices

throughout the valuation.

Figure 74: Macro assumptions


We expect Russia’s actual GDP to grow at a healthy 6.5%-7.2% per year in 2008-2010, and then

to slow to a long-term growth rate of 5.5%. This is generally in line with the government’s

economic and social-development program, which foresees a CAGR of approximately 6.0%

through 2020 for Russia’s GDP.

Fuel prices

Our international oil and gas team forecast an average Brent price of USD 100/bbl for 2008, to

decrease to USD 85/bbl by 2011. We indexed Brent prices by 3.0% per year beginning in 2014,

which is generally in line with the historical average US inflation rate.

Figure 75: Oil and gas prices forecast through 2020


In autumn 2006 the government decided to gradually raise domestic gas prices to net back

parity. (Net back parity implies that domestic gas deliveries should effectively have the same

profitability as gas exports to Europe after adjusting for transportation costs and export duties.)

The government approved a schedule for gas tariff hikes that implies average annual hikes of

15%, 25%, 20%, and 27% in 2007, 2008, 2009, and 2010, respectively. The government also

estimated a net back parity of USD 125/mcm; the implied average hike for 2011 (which was to

align domestic gas prices with net back parity) thus stood at 29%.

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

GDP growth 7.8% 7.2% 6.8% 6.5% 6.0% 5.8% 5.5% 5.5% 5.5% 5.5% 5.5% 5.5% 5.5% 5.5%

CPI period end, y-o-y 11.9% 11.5% 10.3% 9.1% 7.9% 7.5% 6.8% 6.5% 5.8% 5.8% 5.8% 5.8% 5.8% 5.8%

PPI period end, y-o-y 13.7% 13.2% 11.3% 9.6% 7.9% 7.5% 6.8% 6.5% 5.8% 5.8% 5.8% 5.8% 5.8% 5.8%

RUB/USD, period average 25.58 24.27 24.50 25.25 25.75 26.25 26.75 27.25 27.75 28.28 28.85 29.42 30.01 30.61

RUB/USD, end period 24.55 24.00 25.00 25.50 26.00 26.50 27.00 27.50 28.00 28.56 29.13 29.71 30.31 30.91

Brent * 73 100 95 90 85 85 85 88 90 93 96 99 101 105

Urals * 70 96 91 87 82 82 82 84 87 90 92 95 98 101

Domestic gas price ** 53 70 86 105 128 157 189 186 192 197 203 209 216 222

Gas price in Europe ** 281 312 429 407 386 364 364 364 375 387 398 410 423 435

Net back gas price level ** 163 174 254 233 211 192 189 186 192 197 203 209 216 222

* USD/bbl

** USD/mcm

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Figure 76: Gas tariff hike schedule

Source: Ministry of Industry and Energy presentation dated November 30, 2006

At the time the government made these estimates and set the schedule for gas price hikes, the

Brent oil price was about USD 65/bbl; however it has since risen significantly. We estimate that in

2011 at a Brent price of USD 85/bbl, net back parity of the domestic gas price will reach USD

211/mcm, effectively requiring a one-off hike of the gas tariff of 111% y-o-y in RUB terms. We

believe the government would be reluctant to make such a sharp hike in one year and would thus

distribute the increase needed to reach net back parity over several years. Furthermore, given

the rapid growth of Brent prices (which by far exceeds government forecasts), we believe that in

order to achieve net back parity reasonably soon, the government should increase domestic gas

tariffs each year no less than the 2008 increase of 25% (vs. the government’s projected hike of

20% in 2010). We forecast that it would take four consecutive hikes of 25% from 2009 to 2012

and a 22% hike in 2013 for domestic gas tariffs to reach net back parity in 2013.

Figure 77: Domestic gas price forecast

Source: Ministry of Industry and Energy, Glitnir estimates

We estimate the effective coal price paid by generators in Russia grew 15% in RUB terms in

2007, and we expect it to advance another 20% in 2008. From 2009 on, we forecast coal prices

will increase in line with the PPI rate.

We expect domestic fuel oil prices will follow the dynamics of global oil prices.

Under the assumptions stated above, we expect the price of gas to exceed the price of coal in

European Russia as early as 2009. Fuel oil is expected to remain the most expensive type of fuel

for the foreseeable future.

51(15%)

63(25%)

72(13%)

81(13%)

91(13%)

102(12%)

Net back parity as of

2006

125 (22%)

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Gas price in Europe

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111% in RUB terms required hike to reach net-back parity in 2011 based

on government scenario


Figure 78: Domestic fuel price forecast



Power consumption

The general scheme for power facility allocation approved by the government in February 2008

envisages a power consumption CAGR of 4.1% for 2007-2020 in the base scenario, and of 5.3%

in the maximum scenario. The maximum scenario assumes the Siberia and East regions will

demonstrate more rapid growth rates than European Russia.

Figure 79: Government forecast for power consumption growth


We believe the government’s forecast of power consumption is too aggressive for the following

reasons:

1. Since reaching its lowest level in 1998, the annual growth rate of power consumption

has exceeded 4.1% only once: in 2006, when it reached 4.5%. In 2007 consumption

increased far less, at 2.0%.

2. The power efficiency of the Russian economy is low compared with that of other

countries. Russia thus probably has significant unrealized potential to reduce its power

consumption/GDP ratio. Liberalisation of the electricity market and corresponding

increases in electricity prices are likely to serve as a trigger for the country-wide

introduction of power-saving technologies.

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2011-

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2020

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2007-

2020

Center 5.3% 4.3% 4.0% 4.5% 5.2%

North West 7.1% 4.4% 4.3% 5.1% 5.5%

Volga 4.1% 2.3% 2.5% 2.9% 4.6%

South 5.3% 3.3% 2.6% 3.6% 5.2%

Urals 5.0% 3.6% 3.8% 4.0% 4.9%

European Russia average 5.3% 3.7% 3.7% 4.2% 5.1%

Siberia 5.1% 3.0% 3.5% 3.8% 5.7%

Total Russia centralized

(incl. Far East and Isolated)5.2% 3.6% 3.7% 4.1% 5.3%

CAGR base govt. scenario


Figure 80: Electricity consumption vs. GDP, 2007 (PPP)

Source: UES, IEA, CIA

We found the electricity consumption growth rates foreseen by the scheme for power facility

allocation to be too bullish. We therefore used them as a base and adjusted them down one-third

each year in order to derive the forecasts that we used throughout the valuation.

Figure 81: Electricity consumption forecast, Russia total


In the government’s base scenario around 186 GW of new installed capacity would be

constructed by 2020, which is 88% of current total installed capacity in Russia. In the maximum

scenario, around 236 GW of new capacity would be added over the same period, which is 112%

of Russia’s current total installed capacity. When comparing these numbers to the government’s

forecast of increases in power consumption through 2020 (74% and 104% for the base and

maximum growth scenarios, respectively), it becomes evident that the general scheme for power

facility allocation presents significant risks of capacity oversupply.

Figure 82: Government forecast for installed capacity


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CAGR base 5.2%

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CAGR Glitnir 3.4%

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CAGR Glitnir 2.5%

CAGR 2007-2020 max scenario 5.3%

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Unfortunately the state and UES have taken certain measures to ensure that after the change of

ownership structure in the generation segment, the new capacities envisaged by the general

scheme for power facility allocation are actually constructed. For instance, in relinquishing control

over OGKs and TGKs in 2007-2008, UES has required that the new owners sign special

capacity-delivery contracts. UES stated that the purpose of these contracts was to guarantee the

capex planned for the generation companies would be implemented after ownership changed

hands. These capacity-delivery contracts effectively link the capex of each generation company

to the general scheme for power facility allocation.

The text of the contracts has not been officially disclosed to the public, but various media sources

report that the contracts include the following conditions:

1. The contract must be signed by three parties: the new owner, the ATS, and the

clearing house.

2. The new owner is responsible for constructing new power blocks of a certain capacity

in a certain location by a specific time.

3. If the new owner does not construct the required power blocks or is late in doing so,

there is a penalty. The size of the penalty can reportedly reach up to 25% of planned

capex.

4. The terms of the contract can be altered if observed needs for new capacity differ from

the original plan.

Therefore it seems that capacity-delivery contracts bring no benefits to the generators, only

obligations. Moreover, they may present a significant risk of capacity oversupply if actual growth

of power demand falls short of the government’s forecast, which we believe is a likely scenario.

The terms of the capacity-delivery agreements and the degree to which the assets’ owners are

flexible to make their own decisions are not clear, but we believe the government could hardly

prevent the new owners from making economically reasonable decisions such as cancelling

construction of a power station if there is not sufficient demand. Therefore, we believe investment

projects that have already begun are likely to be realized, but projects that are only in the

preparation stage are likely to be amended or cancelled if actual growth of power consumption

differs drastically from the government’s forecast.

Production

We built an electricity-market model to forecast production volumes for every generator in Russia

through 2020. We modelled production volumes for the European and Siberian pricing zones

separately.

Our model incorporates both first-wave investment projects that have already begun and those

we consider likely to be realized. Overall we accounted for 48 GW of new capacity to be

commissioned by 2015 (80% of which should be completed by 2013). We do not consider it

practical to factor in projects more remote in time (commissioned for 2016 and beyond) for the

following reasons:

1. The parameters of these projects are likely to change materially.

2. Under our assumptions of electricity consumption growth, the first wave of projects

should be sufficient to cover electricity demands through 2020; therefore we believe

many remote projects will be cancelled.


Figure 83: Installed electric capacity



Our model is based on actual 2007 production data from each power plant and incorporates the

following assumptions:

1. Load factors for existing nuclear and hydroelectric plants equal the historical averages.

2. The maximum load factor is 80% or the historical high for existing condensing power

plants (GRESs), and 65% or the historical high for combined heat and power plants

(CHPs). The minimum load factor for GRESs and CHPs is 20%.

3. Load factors for new nuclear, gas-fired, and CHP plants are assumed to remain

constant at 80%, 80%, and 65%, respectively.

At projected rates of electricity consumption growth and capacity commissioning, we expect new

capacity will put pressure on existing plants’ production volumes.

Figure 84: Electricity generation



Excessive new capacity will hurt the least-efficient generators (those with a high fuel burn rate)

the most. These include GRESs and CHPs operating in condensing mode. The load factors of

nuclear and hydroelectric power plants are unlikely to suffer from new additions.

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Figure 85: Average load factor



We expect the load factors of existing generators will recover by 2020 if there are no further

additions of capacity after 2015, or if demand grows faster than expected.

Electricity prices

Under the current regulatory framework, generators receive two separate revenue flows: one

from electricity sales (which aims to cover variable costs such as fuel) and one from capacity

sales (which aims to cover fixed costs and cost of capital).

The government has approved the establishment and liberalisation of the electricity market;

however, it has made no decisions on the rules for the capacity market yet.

We modelled regulated and market-based electricity prices and capacity payments separately,

meaning we effectively came up with four different prices.

We forecast that electricity volumes sold under regulated tariffs would decrease to 0% by the end

of 2010, in line with the government’s schedule for the liberalisation of the electricity market. We

thus assumed that from 2011 on, all electricity would be sold at unregulated prices.

We expect that the first capacity auction will take place in 2H08 and will determine unregulated

capacity prices for 2009. The legislation stipulates the capacity market must be liberalised at the

same pace and simultaneously with the electricity market. Therefore we expect that beginning

January 1, 2009, the share of capacity traded through market-based mechanisms will reach

30%, which is equal to the share of liberalised volumes on the electricity market. For the reasons

presented in the following pages, we expect the capacity market to be fully liberalised beginning

in 2014.

The adopted rules also stipulate that newly commissioned power plants sell 100% of output at

unregulated electricity prices; we expect these plants to sell 100% of capacity at market-based

prices beginning in 2009.

Regulated tariffs

We forecast regulated tariffs for both electricity and capacity to increase at rates that will

effectively maintain the same operating profitability as implied in the 2008 tariffs. We forecast

regulated tariffs for each generator separately.

Free market price

Theoretically, in a competitive market the total equilibrium price for electricity (i.e. the sum of the

electricity price and capacity payment) should, over the long term, converge to the cost of a new

entrant. The cost of a new entrant is the total compensation required by an investor constructing

a power plant and should cover all economic costs, including fuel, operations and management,

and cost of capital. A new entrant is a marginal power station that meets the marginal increase in

power demand.

In Russia’s two-price electricity market, unregulated electricity prices should converge to the fuel

costs of a new entrant, while market-based capacity payment should converge to the capacity

cost of a new entrant (i.e. the sum of operations and management expenses, tax, and cost of

capital).

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Cost of new entrant

We estimated new entrant cost separately for the European and Siberian pricing zones. We

considered gas- and coal-fired power plants as those able to handle marginal electricity demand

for the following reasons:

1. Gas- and coal-fired power plants are flexible enough to respond to rapidly changing

power consumption (i.e. they are able to handle intra-day highs and lows) as opposed

to nuclear plants, which can only produce the base load.

2. Gas- and coal-fired power plants can be constructed in practically any location, as

opposed to hydroelectric plants, which are dependent on natural conditions.

3. Thermal power plants (gas- and coal-fired) are the price-setters in the electricity

market in both the European and Siberian pricing zones, and are expected to remain in

this position going forward.

Figure 86: Merit order curve, 2007



Figure 87: Merit order curve, 2012e



We used the following assumptions on typical characteristics of gas and coal power plants in

calculating the cost of a new entrant.

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Figure 88: New-entrant assumptions


Our forecast for fuel price dynamics is discussed in ―Macro assumptions: Fuel prices‖.

We assumed the cost of construction for gas and coal power plants as of 2008 to be USD

1 060/kW and 1 380/kW, respectively. Our assumptions may be on the conservative side: some

OGKs and TGKs report construction costs as high as USD 1 250/kW for gas-fired and USD

1 745/kW for coal-fired capacity. We indexed the cost of new construction by 3.0% in USD terms

going forward.

We assumed a new generator’s fixed costs to be 15% below the average seen across OGKs and

TGKs. Going forward, we indexed fixed costs with the expected PPI rate.

We used a 1.0% company-specific risk premium for calculating new-entrant cost, rather than our

standard company-specific risk premium for OGKs and TGKs of 2.5%. This is because we

consider newly commissioned power plants to have less regulatory risk than existing plants.

Figure 89: Cost of new entrant, total


Comparing the costs of new entrants of various types led us to the following conclusions:

1. In European Russia, it is economically justified to construct a gas-fired plant because

of the lower new-entrant cost. This is true through 2013, when the price of gas will

reach its peak in Russia. From 2014 onwards it generally does not matter which type

of power plant is constructed in European Russia, as the cost of new entrant for gas

and coal power plants is practically identical.

2. In Siberia, gas-fired power plants seem to be more economically feasible than coal

plants through 2010, after which coal-fired plants become more attractive due to

soaring domestic gas tariffs.

We must also take into account the underdeveloped nature of the gas transportation network in

Siberia (only the networks in the Tomsk and Omsk regions are developed to any significant

extent), which makes it technically unfeasible to construct gas-fired generators in Siberia on a

large scale.

Thus we assumed a new entrant to be a gas-fired plant in European Russia, and a coal-fired

plant in Siberia.

Gas Coal

Cost of new construction 2008, USD/kW 1 061 1 379

Economic life, years 20 20

Load factor 80% 80%

Fixed O&M costs 2008, USD/kW 36 36

Fuel burn rate, gfe/kWh 220 290

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Figure 90: Cost of new entrant by region

European Russia (gas-fired)

Siberia (coal-fired)

Source: Glitnir estimates Source: Glitnir estimates

According to our estimates, fuel makes up a larger share of the cost of a new entrant in

European Russia, while cost of capital takes a larger share in Siberia. There are two major

factors that determine this relationship:

1. Coal-fired plants are more expensive to construct than gas-fired plants.

2. Coal prices in Siberia are much lower than gas prices in European Russia.

Observed electricity prices vs. cost of new entrant assumptions

Actual market electricity prices as seen on the day-ahead market (ATS) in 2007 were 2.1x higher

than our estimate of new-entrant fuel costs in European Russia and generally in line with our

estimates of new-entrant fuel cost in Siberia. In the first five months of 2008 actual ATS prices

were 110% and 61% above our forecasts for fuel costs of new entrants in European Russia and

Siberia, respectively.

Figure 91: Price dynamics on ATS vs. fuel cost of new entrant



Deviations of actual electricity price from new-entrant fuel cost are normal and can be explained

by the marginal pricing principle on the spot electricity market, according to which the equilibrium

market price equals the fuel costs of a marginal producer. As the marginal producer is by

definition the least efficient generator to cover marginal demand, its fuel costs can significantly

exceed those of a much more efficient new entrant.

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D/M

Wh

Cost of capital

Tax

Operating & maintanance

Fuel

0

10

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30

40

50

60

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80

US

D/M

Wh

Cost of capital Tax Operating & maintanance Fuel

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0

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Ja

n 0

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b 0

7

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r 0

7

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r 0

7

Ma

y 0

7

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n 0

7

Ju

l 07

Au

g 0

7

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p 0

7

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7

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v 0

7

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c 0

7

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n 0

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b 0

8

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r 0

8

Ap

r 0

8

US

D/M

Wh

Actual price Fuel cost of new entrant Average actual price

19.725.6

30.3

10.914.4

81%135%

110%

0

5

10

15

20

25

30

35

Ja

n 0

7

Fe

b 0

7

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r 0

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US

D/M

Wh

Actual price Fuel cost of new entrant Average actual price

5.9

16.9

20.1

9.912.5-40%

71%61%


We expect free market electricity prices to move closer to the fuel cost of new entrant in three to

four years, when the bulk of new capacities will come into operation. However, we believe the

free market electricity price will stay above the fuel cost of a new entrant because of the marginal

pricing principle of the electricity market.

Figure 92: Electricity price forecast



Overall we expect the market electricity price in European Russia to increase 2.0x, from USD

22.7/MWh in 2007 to USD 45.8/MWh in 2013, which implies a relatively modest CAGR of 12.5%.

In Siberia, we expect free market prices to grow 66% over the same period (a CAGR of 8.9%), to

reach USD 18.9/MWh in 2013.

Free-market capacity payment

Following the logic of the electricity market, we expect liberalised capacity payment to converge

to the capacity cost of a new entrant. We define capacity cost of a new entrant as the sum of

fixed costs and the cost of capital.

However, according to our estimates the 2009 market-based capacity payment for European

Russia and Siberia should be about 3.2x and 6.7x higher, respectively, than the current average

regulated capacity tariff. This means that if 30% of capacity begins trading at market-based

prices in 2009, the total effective electricity price (i.e. the sum of effective electricity price and

effective capacity payment) should increase 60% and 122% in a single year in European Russia

and Siberia, respectively. Such a sharp hike would hardly be acceptable from a political

standpoint in our view; we expect the government will introduce price caps on capacity payments

effective for several years in order to smooth growth in total effective electricity price.

For valuation purposes we assumed that as of 2009 market-based capacity payment for existing

generators would be capped at 35% and 30% of its fair level in the European and Siberian

pricing zones, respectively. We assumed these price caps would gradually diminish and be

completely eliminated by 2014, which would allow the hikes in total effective electricity prices to

be smoothed out over several years. We do not expect any price caps for newly constructed

power plants, and assume 100% of their capacity will be paid at fair market-based capacity

payments.

Also, we believe power plants with low load factors (i.e. with idle capacity) are unlikely to be able

to sell the full volume of their capacity. To account for that effect in calculating the market-based

capacity revenue, we adjusted installed capacity down using the following formula:

Installed capacity that receives capacity payment = Installed capacity x

min(100%, load factor + 20%)

This formula implies that a power plant with a load factor of 80% or above receives a market

capacity payment (measured in USD/kW) for 100% of its installed capacity, while a power plant

with a load factor of 50% receives a capacity payment for only 70% of its installed capacity. This

adjustment affects existing power plants only, and given that many of them have low load factors,

we expect that an average free-market capacity payment measured in USD/kW would be

significantly less than the capacity cost for a new entrant.

0

10

20

30

40

50

60

US

D/M

Wh

Free market

Regulated

Average electricity price

Fuel cost of new entrant

0

5

10

15

20

25

30

US

D/M

Wh

Free market

Regulated

Average electricity price

Fuel cost of new entrant


Figure 93: Capacity payment forecast



Reality check: Total effective electricity price

Under our assumptions on electricity prices and capacity payments, we expect the total effective

price for electricity received by generators in Russia to increase 2.8x over 2009-2014, which

implies a CAGR of 18.8%. The total electricity price in Siberia will show a much faster CAGR of

26.1% compared with the total CAGR for electricity price of 17.7% in European Russia.

We believe our estimated price hikes are politically acceptable and tend to be on the

conservative side, as they imply full liberalisation of generators’ top lines by January 1, 2014,

three years after the date envisaged by current legislation.

Figure 94: Total effective price



0

50

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350

US

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Regulated

Average capacity payment

Capacity cost of new entrant

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Total cost of new entrant


Russia total


Siberian generators (many of which are hydroelectric) appear to be more sensitive to the

introduction of the capacity market. We expect the share of capacity payment in their total

electricity price to expand to 73% by 2014, while capacity payment will stand at about 49% for

generators in European Russia.

Heat revenues

Heat production

Due to the lack of reliable data on regional heat markets, we applied a uniform heat production

growth rate of 1% across all generation companies. This is a rather conservative assumption

compared with the actual heat consumption CAGR of 2.1% since 1998.

Heat tariffs

Although this has not been officially announced, we believe regulation of the heat segment is

likely to switch from the current cost-plus approach to an approach that will guarantee sufficient

return on capital for investors. In our view such a change in regulation would be driven by

practically the same factors as in the electricity segment: the need for investments to construct

new heat capacity and modernize old heat-production units.

Probable scenarios of regulatory changes could include the introduction of competitive heat

markets and the switch to a RAB approach similar to the one planned in the power grid segment.

However, given the slow pace at which the government makes decisions and that deregulation of

the electricity segment a top priority of the government at the moment is not yet fully

complete, we believe it is reasonable not to expect changes in the regulation of the heat segment

any time soon.

In order to be conservative, for valuation purposes we assumed regulation of the heat segment

would continue to be based on the current cost-plus approach for the foreseeable future.

However we expect the regulator will set tariffs, which would imply improvement in profitability

over time. This was somewhat confirmed by statements of Elvira Nabiullina, the head of the

Ministry of Economic Development and Trade, who in May 2008 declared the government’s

intentions to improve the profitability of the heat segment through 2011.

We thus forecast that the average operating margin of the heat segment in Russia will expand to

13% by 2011 (vs. our estimate of 8.4% as of 2006). We also expect that dispersion of operating

profitability of the heat segment across companies will diminish over time.

0

20

40

60

80

100

120

US

D/M

Wh




Figure 95: Heat business operating margin

2006 2011e


However, we believe certain differences in the profitability of the heat segment among

companies are sustainable over time. This is mainly related to differences in the ability of

generation companies to negotiate favourable tariffs with local authorities. Those companies that

have managed to negotiate favourable heat tariffs are likely to continue doing so in the future;

those that have not are less likely to be successful in this going forward.

Costs

For valuation purposes, we split the total operating costs of generation companies into three

components fuel costs, fixed costs, and depreciation each of which we modelled separately.

Fuel costs

Fuel cost per unit of output is determined by three parameters: fuel burn rate, fuel prices, and

fuel mix.

Fuel burn rate

We took the most recent company data on fuel burn rates of power stations; for valuation

purposes we assumed fuel burn rates of existing generators would remain constant over the

forecast period.

Figure 96: Fuel burn rates in electricity production, 2007

Average 2006 8.4%

OGK-1OGK-2OGK-3OGK-4OGK-5OGK-6TGK-1TGK-2

MosenergoTGK-4TGK-5TGK-6TGK-7TGK-8TGK-9

TGK-10TGK-11

KuzbassenergoTGK-13TGK-14

BashkirenergoIrkutskenergo

NovosibirskenergoFar East Gen. Co.

-30% -10% 10% 30%

Average 2011e 13%



TGK-10TGK-11




-30% -10% 10% 30%

0

50

100

150

200

250

300

350

400

450

TG

K-3

No

vo

sib

irske

ne

rgo

TG

K-5

TG

K-1

TG

K-1

0

Irku

tske

ne

rgo

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sh

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en

erg

o

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1

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K-4

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K-3

TG

K-8

DG

K

OG

K-6

TG

K-1

2

TG

K-9

TG

K-1

4

g/k

Wh



Figure 97: Fuel burn rates in heat production, 2007


Fuel burn rates are measured in grams of fuel equivalent per kilowatt hour and kilograms of fuel

equivalent per gigacalorie. The energy content of one ton of fuel equivalent equals 7 000 kJ.

Fuel prices

Our forecast of fuel prices on an individual-company level is based on actual fuel prices as

implied in the companies’ most recent financial statements; going forward we indexed them

proportionally to our general forecast for commodity prices, which is presented in the ―Macro

assumptions‖ section.

Fuel mix

With a few exceptions, we do not expect significant changes in the fuel mix of existing power

plants going forward. For those generation companies that have the technical ability and that

have announced plans to switch from one type of fuel to another (typically from gas to coal), we

incorporated this change into our models (for OGK-1, OGK-2, OGK-4, OGK-6, TGK-2, and TGK-

6).

Fixed costs

Using regression analysis we derived an estimate of average fixed costs among generation

companies for 2006 of USD 31.0/kW of electric capacity, and USD 11.1/GCal/h of heat capacity.

Fixed costs on a per-capacity basis vary widely among generators. Although there are

fundamental reasons for this, we believe a significant portion of dispersion across companies is

caused by the current regulatory regime. Under the cost-plus approach it seems economically

reasonable for generation companies to inflate costs in order to receive a higher tariff. As a

result, the relative size of fixed costs reflects more of the generator’s ability to negotiate allowed

costs and thus tariffs with the FST than what would be justified by fundamental reasons. We

expect that dispersion of fixed costs among generators will diminish as the portion of electricity

and capacity sold at unregulated prices expands.

We indexed reported fixed costs with the expected PPI rate going forward and included a

convergence factor that effectively reduces dispersion of fixed costs among generation

companies by a third.

0

20

40

60

80

100

120

140

160

180

200

TG

K-5

Irku

tske

ne

rgo

TG

K-7

No

vo

sib

irske

ne

rgo

TG

K-1

1

TG

K-1

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0

Ba

sh

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erg

o

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TG

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TG

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2

DG

K

TG

K-1

4

OG

K-4

TG

K-3

OG

K-1

OG

K-3

kg

/Gca

l


Figure 98: Fixed cost of electric capacity, USD/kW, 2006 and 2011e


Figure 99: Fixed cost of heat capacity, 2006 and 2011e


Depreciation

We extrapolated actual depreciation rates implied in companies’ financial statements to converge

to an industry-average depreciation rate of 4.0% by 2011.

Capex

We modelled two constituent parts of total capex expense separately: maintenance capex

required to keep existing capacity in working condition, and capex on new power plants.

Maintenance capex

Annual maintenance capex was calculated as follows:

Annual maintenance capex = Construction cost of a new power plant of the same fuel

type / Plant’s expected physical life



TGK-10TGK-11




0 10 20 30 40 50 60 70 80USD thous./MW

Fixed electricity cost, 2006 Fixed electricity cost, 2011e

Average 2006 Average 2011e



TGK-10TGK-11




0 5 10 15 20 25 30 35 40

USD thous./Gcal/h

Fixed heat cost, 2006 Fixed heat cost, 2011e

Average 2006

Average 2011e


In calculating maintenance capex, we used the same assumptions regarding cost of construction

as in our calculation of the cost of new entrant (see ―Free market prices: Cost of new entrant‖):

USD 1 060/kW and USD 1 380/kW of gas and coal installed capacity, respectively, as of 2008.

For hydroelectric power plants we assumed a cost of new construction of USD 2 120/kW as of

2008. We assumed a physical life of 50 years for thermal plants and of 80 years for hydroelectric

plants.

Capex in new power plants

We evaluated each of the 73 investment projects of the generation companies separately and

then consolidated them with existing assets. The following assumptions were used in estimating

cash flows for each investment project:

The size, fuel type, location, and timing of construction of power blocks is respective to

company data.

Initial investment outlay and fixed costs per kilowatt, fuel burn rate, and load factor are

the same as those used in calculating the cost of a new entrant. Load factors for

hydroelectric power plants come from company data.

Fuel price equals the actual fuel price of the plant where the new block is being built, or

the fuel price of a neighbouring power plant if the new block is stand-alone.

Starting from the date of commission, 100% of output and 100% of capacity is sold at

an unregulated electricity price and market-based capacity payment, respectively.

Taxation of hydroelectric plants

Due to their lack of fuel costs and lesser fixed costs compared with thermal generators,

hydroelectric power plants will be the main beneficiaries of the liberalisation of the electricity

market. According to our estimates, when the amount of electricity sold at free prices reaches

100% in 2011, the EBITDA margin of RusHydro, the largest owner of hydroelectric power

stations in Russia, will expand to around 82% (from 36% in 2006), and net margin will increase to

54% (from 12% in 2006), implying a return on equity of around 23%. Such high profitability is

hardly sustainable in the long term in our view.

We thus assumed that beginning in 2012 the government would tax RusHydro’s huge profits by

an amount that would return the company’s profitability to normal levels. For valuation purposes

we assumed that from 2012 onwards RusHydro’s existing assets would be earning a return on

equity of 11.0%, which corresponds to the required increase of the effective corporate tax rate

from the authorized 24% to 60%. For the sake of consistency, we also applied this 60% effective

tax rate to hydroelectric assets owned by TGK-1, TGK-8, Irkutskenergo, and Bashkirenergo.

Discount rate and terminal growth

We estimated cost of equity for utility companies as the sum of market risk, sector risk, and a

company-specific risk adjustment.

Figure 100: Market risk calculation

Source: Glitnir research

Sector risk is mainly related to government regulation and corresponds with our subjective

assessment of risks regarding expected changes in the regulation of a particular segment. We

assumed 2.5% sector risk for generation companies, 1.5% for distribution and transmission grids,

and 1.5% for Far East and isolated energy companies. For independent energy companies, the

sector risk is a mix of the risk for generation companies and grids; we estimated it at roughly

2.5%.

Company-specific risk is a complex measure of a company’s corporate governance,

transparency, and stock liquidity. Company-specific adjustment is subjective, but we note the

following relationships:

1. A 0.5 pp decrease in the cost of equity for OGKs and TGKs acquired by major foreign

power companies, as the latter are likely to bring their extensive expertise

2. Upward company-specific adjustment for several cases. For the source of risk in each

specific case, see ―Appendix 1: Company-specific issues.‖

Source

Sovereign risk-free rate 5.9% Russia 2028 YTM

Standard equity risk premium 5.0% Glitnir research

Market risk 10.9%


OGK-1: Risks related to its joint venture with TNK-BP

TGK-11: Risks related to the dispute with Rosneft

RusHydro, Irkutskenergo, and Krasnoyarsk GES: Transfer pricing risks

3. Poor corporate governance and transparency in independent energy companies

(Bashkirenergo, Irkutskenergo, and Novosibirskenergo)

Figure 101: Discount rate calculation, generation companies


We applied a uniform nominal terminal growth rate of 2.0% to all utility companies.

Valuation results

Based on the assumptions outlined above, we built DCF models for each generation company.

Summaries of the DCF and financial statements for 22 generation companies are presented in

―Appendix 3: Company profiles.‖

Under the assumptions outlined above we estimate that market liberalisation will result in

substantial improvement in the earnings of generation companies.

Company

Market

risk

Sector

risk

premium

Liquidity

risk

premium

Corp. gov. risk

premium (+) /

discount (-) RROE

Cost

of

debt

Effective

tax rate

After-

tax

cost

of

debt

Target

D/A

Required

WACC

Terminal

growth

Generation

OGK-1 10.9% 2.5% 0.5% 1.5% 15.4% 9.0% 24.0% 6.8% 30.0% 12.8% 2.0%

OGK-2 10.9% 2.5% 0.5% 1.0% 14.9% 9.0% 24.0% 6.8% 30.0% 12.5% 2.0%

OGK-3 10.9% 2.5% 0.5% 0.5% 14.4% 9.0% 24.0% 6.8% 30.0% 12.1% 2.0%

OGK-4 10.9% 2.5% 1.0% -0.5% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

OGK-5 10.9% 2.5% 0.0% -0.5% 12.9% 9.0% 24.0% 6.8% 30.0% 11.1% 2.0%

OGK-6 10.9% 2.5% 0.5% 1.0% 14.9% 9.0% 24.0% 6.8% 30.0% 12.5% 2.0%

TGK-1 10.9% 2.5% 0.5% 1.0% 14.9% 9.0% 24.0% 6.8% 30.0% 12.5% 2.0%

TGK-2 10.9% 2.5% 0.5% -0.5% 13.4% 9.0% 24.0% 6.8% 30.0% 11.4% 2.0%

Mosenergo 10.9% 2.5% 1.0% 1.0% 15.4% 9.0% 24.0% 6.8% 30.0% 12.8% 2.0%

TGK-4 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-5 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-6 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-7 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-8 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-9 10.9% 2.5% 0.5% 0.0% 13.9% 9.0% 24.0% 6.8% 30.0% 11.8% 2.0%

TGK-10 10.9% 2.5% 0.5% -0.5% 13.4% 9.0% 24.0% 6.8% 30.0% 11.4% 2.0%

TGK-11 10.9% 2.5% 0.5% 3.0% 16.9% 9.0% 24.0% 6.8% 30.0% 13.9% 2.0%

Kuzbassenergo 10.9% 2.5% 0.5% 0.5% 14.4% 9.0% 24.0% 6.8% 30.0% 12.1% 2.0%

TGK-13 10.9% 2.5% 0.5% 0.5% 14.4% 9.0% 24.0% 6.8% 30.0% 12.1% 2.0%

TGK-14 10.9% 2.5% 2.0% 0.0% 15.4% 9.0% 24.0% 6.8% 30.0% 12.8% 2.0%

RusHydro 10.9% 2.5% 0.0% 1.5% 14.9% 9.0% 24.0% 6.8% 30.0% 12.5% 2.0%

Krasnoyarsk GES 10.9% 2.5% 0.5% 5.0% 18.9% 9.0% 24.0% 6.8% 30.0% 15.3% 2.0%

Isolated

Far East Energy Co. 10.9% 1.5% 0.5% 0.0% 12.9% 11.0% 24.0% 8.4% 30.0% 11.5% 2.0%

Integrated

Bashkirenergo 10.9% 2.0% 0.5% 1.5% 14.9% 9.5% 24.0% 7.2% 30.0% 12.6% 2.0%

Irkutskenergo 10.9% 2.0% 0.5% 3.0% 16.4% 9.5% 24.0% 7.2% 30.0% 13.6% 2.0%

Novosibirskenergo 10.9% 2.0% 0.5% 1.5% 14.9% 9.5% 24.0% 7.2% 30.0% 12.6% 2.0%


Figure 102: EBITDA/kW

2007e 2014e


0

5

10

15

20

25

30

35

40

OG

K-2

Kra

sn

oya

rsk G

ES

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K-8

Ba

sh

kir

en

erg

oT

GK

-1T

GK

-6O

GK

-6T

GK

-13

TG

K-5

OG

K-4

No

vo

sib

irske

ne

rgo

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Irku

tske

ne

rgo

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Mo

se

ne

rgo

Fa

r E

ast

GC

TG

K-1

4T

GK

-9O

GK

-3T

GK

-11

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K-1

0H

yd

roO

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K-2

Ku

zb

asse

ne

rgo

US

D/k

W

0

50

100

150

200

250

300

350

Fa

r E

ast

GC

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K-6

OG

K-3

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K-6

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OG

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TG

K-5

TG

K-7

Ba

sh

kir

en

erg

oT

GK

-4O

GK

-2T

GK

-2T

GK

-8T

GK

-11

No

vo

sib

irske

ne

rgo

TG

K-9

Mo

se

ne

rgo

OG

K-4

TG

K-1

4T

GK

-13

TG

K-1

0K

uzb

asse

ne

rgo

TG

K-1

Irku

tske

ne

rgo

Hyd

roO

GK

Kra

sn

oya

rsk G

ES

US

D/k

W


Figure 103: Valuation results


Cur-

rent

Tar-

get

Electr.

g/kWh

Heat,

kg/Gcal gas coal

fuel

oil other electr. heat

Generation

OGK-1 common 5 124 0.115 0.132 0.090 46% Buy 444 631 9 531 2 572 47 752 1 053 329 169 1 274 92% 7% 1% 0% 60% 5%

OGK-2 common 4 888 0.149 0.172 0.088 95% Buy 286 582 8 695 1 814 45 419 2 338 344 151 1 131 75% 24% 1% 0% 63% 15%

OGK-3 common 6 702 0.141 0.161 0.116 39% Buy 281 471 8 497 1 675 30 248 1 285 345 180 1 300 59% 38% 3% 0% 43% 9%

OGK-4 common 9 201 0.146 0.166 0.080 108% Buy 416 1 005 8 630 2 179 52 140 2 226 324 162 989 83% 16% 0% 1% 72% 12%

OGK-5 common 6 562 0.186 0.209 0.128 64% Buy 509 826 8 672 2 392 36 481 6 769 336 140 1 281 55% 44% 1% 0% 51% 32%

OGK-6 common 2 855 0.0885 0.102 0.078 30% Buy 230 300 9 052 2 704 31 297 4 366 362 153 1 575 50% 48% 2% 0% 43% 18%

TGK-1 common 5 073 0.00132 0.00151 0.00134 13% Hold 687 757 6 280 14 754 24 159 25 397 311 143 1 717 96% 3% 2% 0% 47% 20%

TGK-2 common 1 755 0.00120 0.00136 0.00100 36% Buy 484 664 2 583 12 471 8 710 18 865 333 147 2 227 57% 15% 27% 1% 45% 17%

preferred 0.000734 0.000832 0.000725 15% Hold

Mosenergo

(TGK-3) common 9 710 0.244 0.278 0.177 57% Buy 615 966 11 117 34 289 58 084 65 557 254 166 1 437 98% 1% 0% 0% 65% 22%

TGK-4 common 2 424 0.00125 0.00142 0.00105 35% Buy 567 763 3 312 17 735 11 074 25 997 342 150 1 527 98% 1% 1% 0% 44% 17%

preferred 0.000623 0.000707 0.000555 27% Buy

TGK-5 common 1 778 0.00145 0.00165 0.00078 112% Buy 227 628 2 467 9 040 9 705 16 672 296 136 1 438 89% 7% 1% 3% 51% 21%

TGK-6 common 1 660 0.00089 0.00102 0.00073 39% Buy 309 454 3 140 10 824 10 983 16 811 332 147 1 660 95% 3% 2% 0% 45% 18%

TGK-7 common 4 425 0.148 0.168 0.090 87% Buy 353 676 6 880 31 143 23 227 44 020 326 140 1 478 100% 0% 0% 0% 44% 16%

TGK-8 common 2 644 0.00128 0.00146 0.00167 -12% Reduce 769 606 3 602 13 381 13 261 13 908 347 146 1 493 100% 0% 0% 0% 47% 12%

TGK-9 common 3 052 0.000390 0.000439 0.000300 46% Buy 569 877 3 280 16 448 13 919 41 500 376 152 1 446 81% 17% 2% 0% 57% 29%

TGK-10 common 5 155 5.87 6.65 4.61 44% Buy 718 1 179 3 253 14 571 18 549 23 922 315 144 1 173 95% 5% 0% 0% 73% 19%

TGK-11 common 943 0.00184 0.00215 0.00112 92% Buy 288 535 2 026 8 202 7 083 13 715 334 143 1 203 51% 48% 1% 0% 46% 19%

Kuzbassenergo

(TGK-12) common 3 022 0.0428 0.0490 0.0235 109% Buy 327 716 4 387 8 842 20 677 14 630 365 154 980 6% 93% 2% 0% 60% 19%

TGK-13 common 2 753 0.0173 0.0198 0.0083 140% Buy 467 765 2 475 7 401 10 107 13 085 339 151 691 0% 99% 1% 0% 53% 20%

TGK-14 common 338 0.000434 0.000501 0.000325 54% Buy 381 578 643 2 277 1 997 3 966 396 161 1 097 0% 100% 0% 0% 42% 20%

Kuban GC common 300 16.8 19.1 11.5 66% Buy 306 494 696 856 4 924 978 366 150 1 682 100% 0% 0% 0% 87% 13%

RusHydro common 25 391 0.0955 0.110 0.085 29% Buy 780 1 038 24 043 n/a 81 495 n/a n/a n/a n/a n/a n/a n/a n/a 40% n/a

Krasnoyarsk GES common 3 314 8.47 10.1 4.0 153% Buy 257 634 6000 n/a 20 631 n/a n/a n/a n/a n/a n/a n/a n/a 40% n/a

Integrated

Bashkirenergo common 3 744 3.52 4.04 1.59 155% Buy 346 831 5 147 17 349 21 204 31 657 327 144 1 284 93% 1% 6% 0% 56% 21%

preferred 1.50 1.72 1.56 11% Hold

Irkutskenergo common 8 774 1.84 2.14 0.88 143% Buy 327 776 12 880 13 002 52 339 23 985 320 139 783 0% 100% 0% 0% 52% 21%

Novosibirskenergo common 2 068 138 159 71 125% Buy 513 1 022 2 522 7 246 9 313 13 171 293 141 1 128 8% 92% 1% 0% 47% 21%

preferred 78.1 89.7 46.0 95% Buy

Isolated

Far East Energy Co. common 1 813 0.105 0.119 0.073 64% Buy 358 450 5 842 12 641 16 403 15 786 357 160 1 570 13% 86% 2% 0% 38% 14%

Fuel mix, 2007

Generation

load factor,

2007

Fuel

consumption,

2007

Installed

electric

capacity

2007, MW

Installed

heat

capacity

2007,

Gcal/h

Elec-

tricity

sales,

2007,

GWh

Fuel

price,

USD/

tfe,

2007

Heat

sales,

2007,

Gcal

thous.

12m TP,

USDCompany

EV/

Installed

capacity,

USD/kW

Mid-

market

price as

of Jun

19, 2008,

USD

Upside

to TP,

% RatingType

Fair

Mcap,

USD

mn FV, USD


Thermal vs. hydroelectric

At target value, we estimate RusHydro’s EV/capacity at USD 1 038/kW, 64% above the average

for OGKs of USD 633/kW. We believe RusHydro deserves a higher valuation per kilowatt of

installed capacity compared with thermal generators due to the absence of fuel expenses.

However, several factors diminish the company’s fair premium to thermal generators:

1. Water tax. Hydroelectric plants are subject to a special water tax, which we expect will

be the government’s means of taking away the huge profits earned by hydro assets in

a fully liberalised market. We forecast 60% effective corporate tax for hydro assets in

2012.

2. Load factor. Hydroelectric plants have an average load factor of 45%, which is far

below the average for OGKs of 55%. The load factor for hydroelectric plants is

dependent on the natural conditions in which a particular plant operates (such as water

flow), and is stable for the long term.

Europe vs. Siberia

Our average target value for OGK power plants located in Siberia of USD 705/kW stands 12%

higher than the average for power plants located in European Russia of USD 627/kW. This is

mainly due to the difference in the assets’ replacement costs. We estimate the full replacement

cost of a new entrant in Siberia at USD 1 380/kW, and in European Russia at USD 1 060/kW.

Thus a market-based capacity payment, which should promote construction of new capacity,

would be higher in Siberia than in European Russia. This effectively means higher electricity

prices and, in turn, a higher value of existing generators in Siberia relative to European Russia.

Coal vs. gas

Comparing coal-fired power plants with gas-fired plants is relevant amongst plants in European

Russia only, as in Siberia there is almost no gas-fired capacity. Coal-fired plants located in

European Russia would have a higher margin than gas-fired plants in the liberalised electricity

market, as gas prices are expected to outperform coal prices going forward (for our assumptions

on commodity prices, see ―Figure 74: Macro assumptions‖). However, the benefits of coal are

partially mitigated by the following factors:

1. Gas-turbine technology allows for more efficient use of fuel compared with the burning

of coal. The fuel burn rate of modern gas-fired power plants of 220 gfe/kWh stands

24% below that of coal power plants (290 gfe/kWh).

2. Coal power plants are more expensive to construct and maintain. We estimate

construction costs of a new coal power plant at USD 1 380/kW, 30% above those of a

gas power plant of USD 1 060/kW.

Our average target valuation of OGK coal-fired power plants in European Russia of USD 760/kW

stands 10% above our average target value of OGK gas-fired power plants of USD 689/kW.

TGKs vs. OGKs

When taking only their electricity business into consideration, we believe TGKs deserve a

discount relative to OGKs on average because TGKs are less sensitive to power consumption

growth. This is due to the technical peculiarity that production at TGKs operating in condensing

mode is much less fuel efficient (and thus more expensive) than at OGKs.

We estimate the target value of the pure electricity-generation business of TGKs at an average

EV/installed capacity of USD 394/kW, 33% below that of OGKs of USD 584/kW.

However, most TGKs have sizable heat production capacity in addition to electricity generation:

their main assets are made up of ―cogeneration‖ power plants, which simultaneously produce

both electricity and heat. Heat is a substantial contributor to the entire value of TGKs, and

furthermore for many TGKs the heat segment exceeds the electricity segment in value. When

taking heat into account, the average target value per kilowatt of electric capacity (the sum of the

target values of the heat and electricity segments divided by electric capacity in kilowatts) of

TGKs increases 96% to USD 771/kW, while that of OGKs increases only 8% to USD 633/kW.


Sensitivity analysis

Figure 104: Target price sensitivity analysis, generation companies


In the table, changes in target prices are a result of changes in the indicated variable by or to the indicated value in each year from 2009 to 2020.

-15% -10% -5% Base +5% +10% +15% -15% -10% -5% Base +5% +10% +15% -15% -10% -5% Base +5% +10% +15%

Generation

OGK-1 -4.4% -2.9% -1.4% 0% 1.4% 3.0% 4.5% 1.7% 1.1% 0.5% 0% -0.5% -1.1% -1.6% -54.6% -37.6% -19.5% 0% 22.3% 45.2% 68.5%

OGK-2 -13.0% -9.5% -4.9% 0% 5.0% 10.0% 15.0% 11.5% 7.6% 3.8% 0% -3.8% -7.3% -10.0% -58.1% -40.2% -20.3% 0% 22.3% 48.1% 74.6%

OGK-3 -1.1% -0.9% -0.5% 0% 0.5% 1.1% 1.8% 1.3% 0.8% 0.3% 0% -0.3% -0.6% -0.8% -26.3% -17.8% -8.9% 0% 10.0% 20.1% 30.3%

OGK-4 -3.0% -2.0% -1.0% 0% 1.0% 2.0% 3.0% -0.2% -0.1% -0.1% 0% 0.1% 0.1% 0.2% -42.1% -29.2% -14.6% 0% 15.7% 31.3% 47.6%

OGK-5 -9.5% -7.4% -4.7% 0% 4.8% 9.6% 14.6% 12.4% 8.2% 4.1% 0% -4.0% -6.4% -8.1% -43.0% -30.3% -16.1% 0% 17.4% 35.1% 53.1%

OGK-6 -8.4% -5.7% -3.0% 0% 3.2% 5.9% 8.8% 10.0% 6.5% 3.5% 0% -3.2% -5.9% -8.6% -59.1% -39.9% -20.3% 0% 22.2% 45.3% 70.5%

TGK-1 -3.8% -2.6% -1.3% 0% 1.3% 2.5% 3.8% -0.8% -0.6% -0.3% 0% 0.3% 0.6% 0.9% -46.3% -31.1% -15.4% 0% 17.0% 33.9% 51.4%

TGK-2 -4.5% -3.0% -1.5% 0% 1.5% 3.0% 4.5% 11.1% 7.4% 3.7% 0% -3.7% -7.4% -11.1% -35.3% -23.6% -11.8% 0% 12.7% 25.5% 38.8%

Mosenergo (TGK-3) -2.2% -1.4% -0.7% 0% 0.7% 1.4% 2.2% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -33.3% -22.5% -11.1% 0% 13.3% 26.4% 39.7%

TGK-4 -1.3% -0.9% -0.4% 0% 0.4% 0.9% 1.3% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -43.7% -29.3% -14.6% 0% 15.8% 31.8% 48.5%

TGK-5 -2.1% -1.4% -0.7% 0% 0.7% 1.4% 2.1% 0.5% 0.3% 0.2% 0% -0.2% -0.3% -0.4% -30.9% -21.1% -10.6% 0% 12.1% 24.3% 37.4%

TGK-6 -1.0% -0.6% -0.3% 0% 0.3% 0.6% 1.0% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -48.3% -32.4% -16.2% 0% 17.5% 35.6% 54.5%

TGK-7 -2.1% -1.4% -0.7% 0% 0.7% 1.4% 2.1% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -24.4% -16.4% -8.3% 0% 9.1% 18.6% 28.8%

TGK-8 -2.4% -1.6% -0.8% 0% 0.8% 1.6% 2.4% 0.1% 0.1% 0.0% 0% 0.0% -0.1% -0.1% -32.4% -21.8% -10.9% 0% 12.0% 24.4% 37.1%

TGK-9 -3.1% -2.1% -1.0% 0% 1.0% 2.1% 3.1% -0.2% -0.1% -0.1% 0% 0.1% 0.1% 0.2% -35.6% -23.8% -11.9% 0% 12.7% 25.6% 39.2%

TGK-10 -3.3% -2.2% -1.1% 0% 1.1% 2.2% 3.3% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -31.4% -21.1% -10.7% 0% 11.5% 23.1% 34.9%

TGK-11 6.2% 4.1% 2.1% 0% -2.1% -4.1% -6.2% -5.1% -3.4% -1.7% 0% 1.7% 3.4% 5.1% -40.3% -26.9% -13.4% 0% 13.4% 26.9% 40.3%

Kuzbassenergo (TGK-12) -0.1% -0.1% 0.0% 0% 0.0% 0.1% 0.1% -0.3% -0.2% -0.1% 0% 0.1% 0.2% 0.3% -35.5% -23.6% -11.8% 0% 11.8% 23.6% 35.5%

TGK-13 0.5% 0.3% 0.2% 0% -0.2% -0.3% -0.5% -1.9% -1.3% -0.6% 0% 0.6% 1.3% 1.9% -22.1% -18.7% -10.1% 0% 7.0% 18.5% 30.2%

TGK-14 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -0.5% -0.3% -0.2% 0% 0.2% 0.3% 0.5% -24.8% -16.5% -8.3% 0% 8.3% 16.5% 24.8%

RusHydro -2.6% -1.8% -0.9% 0% 0.9% 1.8% 2.6% -1.2% -0.8% -0.4% 0% 0.4% 0.8% 1.2% -12.2% -8.2% -4.1% 0% 4.8% 9.4% 14.2%

Krasnoyarsk GES 1.5% 1.0% 0.5% 0% -0.5% -0.9% -1.4% -3.1% -2.1% -1.0% 0% 1.0% 2.1% 3.1% -10.5% -7.1% -3.5% 0% 4.1% 8.2% 12.4%

Integrated

Bashkirenergo -1.9% -1.2% -0.6% 0% 0.6% 1.2% 1.9% -0.9% -0.6% -0.3% 0% 0.3% 0.6% 0.9% -23.6% -16.1% -8.0% 0% 9.6% 19.3% 29.2%

Irkutskenergo 1.5% 1.0% 0.5% 0% -0.5% -1.0% -1.4% -3.8% -2.6% -1.3% 0% 1.3% 2.5% 3.8% -16.5% -11.1% -5.6% 0% 6.1% 12.3% 18.7%

Novosibirskenergo -0.1% 0.0% 0.0% 0% 0.0% 0.0% 0.1% -0.3% -0.2% -0.1% 0% 0.1% 0.2% 0.3% -17.2% -11.5% -5.7% 0% 5.7% 11.5% 17.2%

Gas prices Coal prices Electricity prices


Target price sensitivity analysis, generation companies (continued)


In the table, changes in target prices are a result of changes in the indicated variable by or to the indicated value in each year from 2009 to 2020.

7% 9% 11% 13% 15% 17% 19% -15% -10% -5% Base +5% +10% +15% -1.5% -1.0% -0.5% Base +0.5% +1.0% +1.5%

Generation

OGK-1 -0.5% -0.4% -0.2% 0% 0.2% 0.4% 0.6% -14.4% -9.6% -4.8% 0% 4.8% 9.6% 14.4% -37.0% -24.9% -13.0% 0% 12.0% 18.6% 22.3%

OGK-2 -0.5% -0.3% -0.2% 0% 0.2% 0.4% 0.6% -11.9% -7.9% -4.0% 0% 4.0% 7.9% 11.9% -33.1% -19.9% -8.0% 0% 9.2% 17.4% 21.3%

OGK-3 -0.3% -0.2% -0.1% 0% 0.1% 0.2% 0.3% -9.4% -6.3% -3.1% 0% 3.1% 6.3% 9.4% -30.2% -23.7% -15.0% 0% 13.1% 21.4% 25.0%

OGK-4 -0.3% -0.2% -0.1% 0% 0.1% 0.2% 0.3% -9.8% -6.6% -3.3% 0% 3.3% 6.6% 9.8% -20.6% -10.8% -3.5% 0% 3.8% 6.9% 8.0%

OGK-5 -1.5% -1.0% -0.5% 0% 0.5% 1.1% 1.7% -13.2% -8.8% -4.4% 0% 4.4% 8.8% 13.2% -36.2% -25.6% -12.1% 0% 12.0% 18.6% 22.9%

OGK-6 -2.6% -1.7% -0.9% 0% 0.9% 1.9% 2.9% -20.6% -13.7% -6.9% 0% 6.9% 13.7% 20.6% -61.6% -50.0% -25.9% 0% 25.2% 49.6% 57.8%

TGK-1 -11.1% -7.6% -3.9% 0% 3.9% 8.2% 12.6% -3.7% -2.5% -1.2% 0% 1.2% 2.5% 3.7% 0.3% 0.1% 0.0% 0% 0.1% 0.3% 0.6%

TGK-2 -17.6% -12.0% -6.2% 0% 6.2% 12.9% 19.9% -1.7% -1.1% -0.6% 0% 0.6% 1.1% 1.7% -2.6% -1.9% -1.1% 0% 1.2% 2.3% 3.3%

Mosenergo (TGK-3) -15.3% -10.5% -5.4% 0% 5.4% 11.3% 17.4% -8.5% -5.6% -2.8% 0% 2.8% 5.6% 8.5% -6.9% -5.0% -2.7% 0% 2.9% 4.8% 5.7%

TGK-4 -21.8% -14.9% -7.7% 0% 7.7% 16.0% 24.6% -6.9% -4.6% -2.3% 0% 2.3% 4.6% 6.9% -4.1% -3.1% -1.7% 0% 1.9% 4.2% 6.6%

TGK-5 -14.1% -9.6% -5.0% 0% 5.0% 10.3% 15.8% -8.3% -5.5% -2.8% 0% 2.8% 5.5% 8.3% -6.5% -4.7% -2.6% 0% 2.8% 5.4% 7.3%

TGK-6 -21.5% -14.7% -7.6% 0% 7.6% 15.7% 24.3% -11.2% -7.5% -3.7% 0% 3.7% 7.5% 11.2% -8.2% -6.0% -3.3% 0% 3.6% 7.5% 11.3%

TGK-7 -19.4% -13.2% -6.8% 0% 6.9% 14.2% 21.9% -9.5% -6.3% -3.2% 0% 3.2% 6.3% 9.5% -3.1% -2.4% -1.4% 0% 1.7% 3.7% 6.0%

TGK-8 -10.1% -6.9% -3.6% 0% 3.6% 7.4% 11.4% -6.3% -4.2% -2.1% 0% 2.1% 4.2% 6.3% -4.0% -2.8% -1.5% 0% 1.1% 2.0% 2.9%

TGK-9 -24.9% -17.0% -8.8% 0% 8.8% 18.2% 28.1% -5.2% -3.5% -1.7% 0% 1.7% 3.5% 5.2% -3.4% -2.6% -1.4% 0% 1.6% 2.9% 3.4%

TGK-10 -8.0% -5.5% -2.8% 0% 2.8% 5.9% 9.1% -5.7% -3.8% -1.9% 0% 1.9% 3.8% 5.7% -5.3% -3.8% -2.0% 0% 2.0% 2.8% 3.3%

TGK-11 -22.0% -15.0% -7.8% 0% 7.8% 16.2% 25.0% -13.7% -9.2% -4.6% 0% 4.6% 9.2% 13.7% -6.3% -4.5% -2.4% 0% 2.8% 5.8% 8.8%

Kuzbassenergo (TGK-12) -6.4% -4.4% -2.3% 0% 2.3% 4.7% 7.3% -13.7% -9.1% -4.6% 0% 4.6% 9.1% 13.7% -9.9% -6.5% -2.8% 0% 1.3% 2.4% 3.3%

TGK-13 -5.3% -3.6% -1.9% 0% 1.9% 3.9% 6.0% -8.8% -7.9% -4.2% 0% 2.3% 6.5% 10.1% -6.4% -4.5% -2.4% 0% 2.6% 4.2% 5.2%

TGK-14 -16.9% -11.6% -6.0% 0% 6.0% 12.4% 19.2% -9.7% -6.5% -3.2% 0% 3.2% 6.5% 9.7% -6.6% -4.7% -2.5% 0% 2.8% 6.0% 9.5%

RusHydro 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -4.7% -3.1% -1.6% 0% 1.6% 3.1% 4.7% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0%

Krasnoyarsk GES 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0% -5.9% -3.9% -1.9% 0% 1.9% 3.8% 5.7% 0.0% 0.0% 0.0% 0% 0.0% 0.0% 0.0%

Integrated

Bashkirenergo -12.3% -8.4% -4.3% 0% 4.4% 9.0% 13.9% -8.7% -5.8% -2.9% 0% 2.9% 5.8% 8.7% -8.5% -6.1% -3.2% 0% 3.4% 7.1% 8.8%

Irkutskenergo -2.1% -1.5% -0.8% 0% 0.8% 1.6% 2.4% -5.6% -3.7% -1.9% 0% 1.8% 3.7% 5.5% -1.3% -0.9% -0.5% 0% 0.5% 1.1% 1.8%

Novosibirskenergo -9.1% -6.2% -3.2% 0% 3.2% 6.7% 10.3% -9.2% -6.1% -3.1% 0% 3.1% 6.1% 9.2% -3.5% -2.6% -1.5% 0% 1.7% 3.8% 6.2%

Heat margins Power consumption growth rate, p.a.Cost of new construction



We valued Russian distribution companies on an assets basis.

According to UES and state officials, RAB is to be introduced in four to six pilot regions beginning

July 1, 2008, and in all regions beginning in 2010. The pilot regions have not been officially

announced, but according to recent statements of UES officials they may include Belgorod,

Perm, Astrakhan, Orenburg, Tver, and Kuzbass.

In our valuation we conservatively assumed that all distribution companies would switch to RAB

beginning in 2011, about a year later than the guideline announced by UES and state officials.

We assumed the new regulatory system would provide a return on RAB equal to the WACC

required by investors, and therefore we assumed that each MRSK’s enterprise value should

equal its RAB at the time the new regulation is introduced. Thus to derive the fair value of

MRSKs, we estimated RAB for each MRSK as of our expected RAB introduction date (January

1, 2011) and assumed it to be equal to enterprise value by that date. We subtracted expected net

debt as of YE10 from the company’s YE10 enterprise value to arrive at a YE10e market cap and

discounted it at the required return on equity to arrive at the current fair market cap.

We estimated the 2010e RAB of each MRSK as follows:

2010e RAB = Current depreciated replacement cost of fixed assets (DRC) + Expected

capex through 2010 (excluding connection fee) – Depreciation through 2010

Depreciated replacement cost (DRC) estimate

DRC is made up of two components: replacement cost new (RCN) and accumulated

depreciation rate.

We used the RCN estimates provided by UES for the eight MRSKs it appraised for consolidation

(the effective date of the appraisal was June 30, 2007). We believe this data provides one of the

best estimates of the companies’ RCNs for tariff-setting purposes, as the appraiser used the

approach and inputs most likely to be used by the industry regulator in the future.

We studied the relationship between the RCN estimates provided by the appraiser and various

technical parameters of the electric grids (such as length, electricity throughput, and overall size)

using regression analysis with RCN as a dependent variable. The strongest relationship (adj. R2

= 0.91) was found between RCN and overall grid size (overall size in units is a measure of the

volume of the grid’s assets used by an industry regulator; it comprises grid length and substation

capacity with a common measurement unit). We also found a strong relationship between RCN

and grid length (adj. R2 = 0.89), while the correlation between RCN and electricity throughput was

relatively weak (adj. R2 = 0.21).

Figure 105: RCN vs. overall grid size

Source: UES, Glitnir calculations

y = 0.01006xR2 = 0.91

0

2

4

6

8

10

12

14

0 200 400 600 800 1 000 1 200 1 400

RC

N e

stim

ate

d b

y a

pp

rais

er, U

SD

bn

Size, thous. units

MRSK Center

MRSK Siberia


MRSK South

MRSK Volga

MRSK Urals

MRSK North-West

MRSK North Caucasus


Figure 106: RCN vs. grid length


Figure 107: RCN vs. electricity throughput


We used an estimated RCN per unit of overall grid size of USD 10 060, which we derived from

the regression to estimate the RCNs for the four distribution companies not included in the

appraisal (Moscow City and Moscow United distribution companies, Lenenergo, and

Tyumenenergo).

To calculate DRC, we multiplied RCN by the adjusted depreciation rates reported in regional

distribution companies’ accounting statements. As accounting depreciation rates are easily

manipulated, we adjusted them by twice reducing the deviation of depreciation rates across

MRSKs in order to reduce volatility in estimates of relative fair value for MRSKs as a result of

imperfections in the accounting data.

We compared our RCN and DRC estimates for MRSKs to the gross and net book values,

respectively, of the fixed assets of foreign peers. On average, our RCN estimate was 19% below

the full replacement cost of foreign peers’ fixed assets on a per-kilometre-of-grid basis. The

discount of our DRC estimate for Russian distributors to the net fixed-assets book values of

foreign distributors on a per-kilometre-of-grid basis was even higher, at 58%.

y = 0.0375xR2 = 0.89

0

2

4

6

8

10

12

14

16

0 50 100 150 200 250 300 350 400R

CN

estim

ate

d b

y a

pp

rais

er, U

SD

bn

Length of grid, thous. km

MRSK CenterMRSK Siberia


MRSK Volga

MRSK Urals

MRSK North-West

MRSK North Caucasus

MRSK South

y = 0.145xR2 = 0.21

0

2

4

6

8

10

12

14

0 20 000 40 000 60 000 80 000 100 000

RC

N e

stim

ate

d b

y a

pp

rais

er, U

SD

bn

Electricity throughput, GWh

MRSK Center

MRSK Siberia

MRSK Urals

MRSK South

MRSK Volga


MRSK North-West

MRSK North

Caucasus


Figure 108: RCN and DRC, Russian vs. foreign distribution grids


Company Country

PPE

cost,

USD

mn

Depr.

rate

PPE acc.

depr., USD

mn

PPE

net,

USD

mn

Grid

length,

km

Transformer

capacity, MVA

MVA/

km

PPE

cost,

USD

thous/

km

PPE

net,

USD

thous/

km

EDF Energy plc* UK 12 477 18% -2231 10 246 175 000 83 000 0.47 71 59

Scottish and Southern Energy plc* UK 8 074 41% -3340 4 733 122 388 66 39

SP AUSNET* Australia 1 428 9% -126 1 302 43 384 33 30

Prazska Energeticka Czech Republic 1 159 39% -458 701 11 544 100 61

ELMU Hungary 1 179 51% -605 574 22 242 53 26

Rytu Skirstomieji Lithuania 1 186 12% -143 1 043 62 816 7 548 0.12 19 17

Vakaru Skirstomieji Lithuania 1 062 25% -268 794 57 000 19 14

Eletropaulo Metropolitana S.A. Brazil 4 282 39% -1673 2 610 42 269 12 662 0.30 101 62

Rio Grande Energia Sa Brazil 1 362 29% -395 966 80 669 1 452 0.02 17 12

Average 3 579 29% -1 027 2 552 68 590 26 166 0.23 53 35

WA 29% 0.29 52 37

* Data for power distribution segment only

RCN,

USD

mn

Assumed

acc. depr.,

USD mn

DRC,

USD

mn

RCN,

USD

thous./

km

DRC,

USD

thous./

km

MRSK Center Russia 12 783 66% -8 438 4 345 367 674 44 898 0.12 35 12

MRSK South Russia 9 296 69% -6 413 2 883 248 283 34 487 0.14 37 12

MRSK North Caucasus Russia 4 261 63% -2 694 1 567 105 165 13 084 0.12 41 15

MRSK Center and Volga Russia 8 134 65% -5 316 2 818 250 000 27 400 0.11 33 11

MRSK North-West Russia 6 585 64% -4 190 2 395 162 200 21 628 0.13 41 15

MRSK Siberia Russia 10 459 65% -6 801 3 657 261 000 33 947 0.13 40 14

MRSK Urals Russia 7 360 62% -4 567 2 793 140 971 25 343 0.18 52 20

MRSK Volga Russia 8 522 53% -4 506 4 016 211 958 36 598 0.17 40 19

Moscow Unified Dist. Co. Russia 5 373 60% -3 197 2 175 74 000 40 326 0.54 73 29

Moscow City Dist. Co. Russia 4 762 62% -2 960 1 803 60 457 17 050 0.28 79 30

Lenenergo Russia 3 232 63% -2 043 1 189 52 021 17 932 0.34 62 23

Tyumenenergo Russia 2 086 52% -1 082 1 004 38 328 23 203 0.61 54 26

Average 6 904 62% -4 351 2 554 164 338 27 991 0.24 49 19

WA 63% 0.17 42 16

Discount relative to foreign peers -19% -58%


The discount of Russian distribution companies to their foreign peers on a DRC-to-grid-length basis might seem high, which would call into question the validity of the independent appraiser’s estimates. However, we believe such a large discount is justified for the following reasons:

1. The RCN per kilometre of Russian distribution grids may be lower than that of foreign companies as a result of the lower sophistication of Russia’s grids. If we compare our RCN estimates for Russian distribution companies to the full replacement values of foreign peers with comparable grid sophistication, we find no downward bias in our RCN estimates. For instance, for the Moscow, St. Petersburg, and Tyumen distribution grids, we estimated an average RCN of USD 69 000/km, which is in line with the gross book value/grid length multiple of USD 66 000-71 000/km for distributors in the UK. The Moscow, St. Petersburg, and Tyumen regions are similar to the UK in terms of grid sophistication; however, grid sophistication in these regions is higher than in the rest of Russia.

2. Russian distribution grids have a significantly higher depreciation rate (63%) than their foreign peers (an average of 29% in our sample). This is because neither the utilities sector as a whole nor Russia’s distribution segment in particular has received proper financing for decades.

In the future, the state regulator is likely to show a downward bias in its estimates of RAB (and thus DRC) in order to ensure that tariffs rise at the lowest possible rate. Inflation is a major concern of the Russian government, and officials have frequently cited electricity tariffs as a significant contributor to growth in the country’s consumer price index. Therefore, we believe it is reasonable to be conservative when forecasting the DRC values expected to be adopted by regulators.

We applied a 3.0% annual asset depreciation rate and a 2.0% annual RCN appreciation rate to account for changes in the economic value of assets prior to the RAB introduction date.

Capex In order to estimate initial RAB, we must augment the DRC presented above (as of June 30, 2007) with expected capex through the RAB introduction date (i.e. from 2H07 to 2010). Data on distribution companies’ total planned capex from 2H07 to 2010 was provided in appraisal presentations, which were based on data from the companies’ respective business plans.

In calculating future RAB, we excluded connection fee revenues from total capex. Based on company data for current profitability and financial leverage potential, we made a rough estimate of the 2H07-2010 capex breakdown by source of financing (existing equity, debt, and connection fees) for each MRSK.

We first forecast the maximum amount of capex that could be financed using current operating cash flow (i.e. existing equity), then estimated the amount of capex that could reasonably be financed by debt. The remainder of the company’s capex program was assumed to be financed by connection fees and was not accounted for in the initial RAB estimate.

Figure 109: Capex by source of financing, MRSKs


Existing equity

Debt Connection fee

MRSK Center 1 243 30% 70% 0% 28% 15%MRSK South 1 145 30% 70% 0% 38% 11%MRSK North Caucasus 194 30% 70% 0% 12% 5%MRSK Center and Volga 1 181 40% 60% 0% 40% 13%MRSK North-West 583 60% 40% 0% 23% 22%MRSK Siberia 435 20% 80% 0% 11% 38%MRSK Urals 660 40% 60% 0% 23% 18%MRSK Volga 777 50% 50% 0% 19% 18%Moscow Unified Dist. Co. 2 331 20% 15% 65% 103% 4%Moscow City Dist. Co. 1 645 15% 30% 55% 88% 4%Lenenergo 1 636 15% 20% 65% 133% 3%Tyumenenergo 1 481 50% 50% 0% 142% 11%

Total capex,

USD mn 2H07-2010

% to be financed fromTotal capex 2H07-2010/DRC 1H07

EBITDA 2006/ Total capex 2H07-2010


Differences in the capex financing structures across MRSKs can be explained by the following:

1. Current profitability relative to size of capex program. The higher an MRSK’s current cash flow relative to its capex, the higher the portion of capex that can be financed through internal sources.

2. Leverage potential relative to size of capex program. The higher an MRSK’s capex is relative to its assets, the more capex is to be financed through connection fees.

We expect most MRSKs will rely on debt as a primary source of capex financing. This seems reasonable given the following:

1. Distribution companies’ current operating cash flow is not enough to meet capex needs in full.

2. Distribution companies have relatively little debt and therefore possess substantial unrealized financial leverage potential.

Thus we expect the distribution sector to significantly increase its leverage by 2011.

Figure 110: Debt to assets,* 1H07 and 2010e


Our view that distribution companies will increase their leverage is shared by UES. Alexander Chistyakov, the deputy CEO of FSK, gave a presentation in September 2007 in which he reported that he expected the distribution segment to significantly increase the portion of debt in its capital structure in the coming years.

Figure 111: Capital structure, distribution sector

Source: FSK

Discount rate We applied a 12.4-13.9% required return on equity (RROE) to discount the estimated YE10 market cap to its present value.

Company 1H07 2010eMRSK Center 3% 18%MRSK South 5% 25%MRSK North Caucasus 1% 9%MRSK Center and Volga 1% 19%MRSK North-West 2% 10%MRSK Siberia 4% 12%MRSK Urals 2% 14%MRSK Volga 1% 9%Moscow Unified Dist. Co. 13% 30%Moscow City Dist. Co. -4% 31%Lenenergo -10% 30%Tyumenenergo 2% 31%Total 2% 20%

* Assumed assets are revalued at DRC

0%10%20%30%40%50%60%70%80%90%

100%

2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015eEquity Net debt


Figure 112: Cost of equity calculation, MRSKs


Company

Market

risk

Sector

risk

premium

Liquidity

risk

premium

Corp. gov. risk

premium (+) /

discount (-) RROE

MRSK Center 10.9% 1.5% 0.5% 0.0% 12.9%

MRSK South 10.9% 1.5% 1.0% 0.0% 13.4%

MRSK North Caucasus 10.9% 1.5% 1.0% 0.0% 13.4%

MRSK Center and Volga 10.9% 1.5% 0.0% 0.0% 12.4%

MRSK North-West 10.9% 1.5% 1.0% 0.0% 13.4%

MRSK Siberia 10.9% 1.5% 1.0% 0.0% 13.4%

MRSK Urals 10.9% 1.5% 1.0% 0.0% 13.4%

MRSK Volga 10.9% 1.5% 1.5% 0.0% 13.9%

Moscow Unified Dist. Co. 10.9% 1.5% 0.5% 0.0% 12.9%

Moscow City Dist. Co. 10.9% 1.5% 0.5% 0.0% 12.9%

Lenenergo 10.9% 1.5% 0.5% 0.0% 12.9%

Tyumenenergo 10.9% 1.5% 0.5% 0.0% 12.9%


Valuation results

Figure 113: Target price calculation, MRSKs


MRSK

Center

MRSK

South

MRSK

North

Caucasus

MRSK

Center

and Volga

MRSK

North-

West

MRSK

Siberia

MRSK

Urals

MRSK

Volga

Moscow

Unified

Dist. Co.

Moscow

City Dist.

Co. Lenenergo Tyumenenergo

RCN 1H07, USD mn 12 783 9 296 4 261 8 134 6 585 10 459 7 360 8 522 5 373 4 762 3 232 2 086

Depreciation rate 66% 69% 63% 65% 64% 65% 62% 53% 60% 62% 63% 52%

DRC 1H07, USD mn 4 345 2 883 1 567 2 818 2 395 3 657 2 793 4 016 2 175 1 803 1 189 1 004

Net debt 1H07 *, USD mn 110 150 18 17 39 131 56 21 286 -74 -118 15

Total capex excluding connection fees,

2H07-2010, USD mn1 243 1 145 194 1 181 583 435 660 777 2 331 1 645 1 636 1 481

Initial RAB 2010e, USD mn 5 240 3 760 1 657 3 759 2 804 3 839 3 259 4 578 4 275 3 262 2 672 2 368

Net debt 2010e, USD mn 961 934 151 709 267 473 443 401 1 265 997 793 738

Minority interest 2010e, USD mn 0 972 0 0 0 205 277 0 0 0 0 0

Fair EV/RAB 2010e 1.00 1.00 0.70 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Fair Mcap 2010e, USD mn 4 279 1 853 1 009 3 050 2 536 3 161 2 539 4 177 3 010 2 266 1 879 1 629

Cost of equity 12.9% 13.4% 13.4% 12.4% 13.4% 13.4% 13.4% 13.9% 12.9% 12.9% 12.9% 12.9%

Fair Mcap current, USD mn 3 142 1 346 733 2 265 1 841 2 295 1 843 2 999 2 247 1 627 1 380 1 196

Common shares outstanding*, mn 42 218 49 845 30 112 698 95 786 89 368 87 430 178 578 28 249 28 249 932 274

FV per common share, USD 0.0744 0.0270 24.8 0.0201 0.0192 0.0257 0.0211 0.0168 0.0795 0.0576 1.37 4.37

12m TP common share, USD 0.0840 0.0306 28.1 0.0226 0.0218 0.0291 0.0239 0.0191 0.0898 0.0650 1.55 4.93

Mid-market price as of Jun 19, 2008,

per common share, USD0.0519 n/a 11.5 0.0141 0.0111 0.0183 0.0191 0.0073 0.0885 0.0630 1.75 n/a

Upside to 12m TP 62% n/a 145% 61% 96% 59% 26% 162% 1% 3% -11% n/a

Recommendation Buy n/a Buy Buy Buy Buy Buy Buy Hold Hold Reduce n/a

Target EV/Grid length, USD thous./km 9.8 9.9 8.0 10.1 12.9 11.0 16.6 15.9 38.1 28.5 26.9 35.1

Target EV/Grid size, USD thous./unit 2 740 2 801 1 938 2 666 3 280 2 804 3 890 4 324 5 270 3 642 4 355 6 490

Target EV/DRC 0.82 0.84 0.53 0.89 0.87 0.78 0.83 0.83 1.28 0.95 1.17 1.33

Transformer capacity/Grid length, MVA/km 0.12 0.14 0.12 0.11 0.13 0.13 0.18 0.17 0.54 0.28 0.34 0.61

EBITDA 2006/ DRC 1H07 4.3% 4.4% 0.6% 5.1% 5.2% 4.3% 4.2% 3.4% 13.1% 7.7% 9.7% 15.2%

* Estimated after consolidation of regional distribution companies into MRSK; for Lenenergo adjusted for the additional share issue


The MRSK valuation results are indicative of the following relationships between grid

characteristics and target value:

1. Target EV/kilometre is higher for distribution companies with more sophisticated grids

(measured by the ratio of transformer capacity to grid length).

2. Target EV/kilometre, target EV/DRC, and target EV/size are higher for distribution

companies that have higher short-term returns on assets (for instance, as measured

by EBITDA/DRC).

What do our valuation assumptions imply by 2011?

Based on our assumption that RAB will be introduced in 2011, the average distribution tariff in

Russia should stand about 112% above the 2006 level, which implies a CAGR of 16% over five

years. We believe the government will find this growth rate acceptable, though high enough for it

to be reluctant to allow tariffs to advance any faster.

Figure 114: Implied distribution tariff, USD/MWh


According to our estimates, the new regulatory regime will boost the sector’s top line to USD 22.1

bn in 2011. Profit margins will also expand for distribution companies, leading to a net income of

USD 3.7 bn for the sector by 2011. Massive capex will drive sector assets up from USD 32.2 bn

in 2006 to USD 41.5 bn by 2011. For selected financials of distribution companies, see

―Appendix 3: Company profiles.‖

Special cases

As Moscow United and Moscow City distribution companies are to be merged, we adjusted their

target values according to the approved swap ratio (1.38 shares of Moscow City Distribution

Company per share of Moscow United Distribution Company).

We also accounted for Lenenergo’s additional share issue in favour of the St. Petersburg city

government at USD 1.58 (RUB 37.44) per share, which is expected to be completed in

November 2008.

As the consolidation of Kurganenergo, Kubanenergo, and Tomsk Distribution Company into

MRSK Urals, MRSK South, and MRSK Siberia, respectively, was rejected by minority

shareholders, we calculated target prices for those companies on a stand-alone basis. We

derived valuations for those companies from the implied fair EV/grid length of the respective

MRSKs and applied 50% company-specific discounts in order to account for lesser liquidity and

higher corporate governance risks of these regional distribution companies relative to larger

MRSKs. Correspondingly, we accounted for minority interest in MRSK Urals, MRSK South, and

MRSK Siberia.

We also applied a 30% discount to MRSK North Caucasus’s EV to account for company-specific

risks related to the general economic and political situation in the region where the company

operates.

Company 2006 2011e

MRSK Center 17 41 137% 17.5%

MRSK South 18 41 124% 16.2%

MRSK North Caucasus 27 71 163% 20.0%

MRSK Center and Volga 15 32 120% 15.8%

MRSK North-West 17 36 108% 14.5%

MRSK Siberia 12 25 106% 14.3%

MRSK Urals 14 26 94% 12.9%

MRSK Volga 16 36 124% 16.2%

Moscow Unified Dist. Co. 15 29 93% 12.8%

Moscow City Dist. Co. 11 29 154% 19.2%

Lenenergo 15 36 139% 17.7%

Tyumenenergo 13 22 70% 10.0%

Total 15 32 112% 14.9%

2011e/

2006

CAGR in

RUB terms



The tables below illustrate the sensitivities of the MRSKs’ target prices to several key variables, including estimated DRC, RAB introduction date (along with tariff CAGR), capex, and RCN appreciation rate.

Figure 115: Sensitivity analysis, MRSKs


2009 2010

Base

2011 2012 2013 2009 2010

Base

2011 2012 2013

MRSK Center 30% 14% 0% -12% -22% 27.3% 21.2% 17.5% 15.2% 13.6%

MRSK South 30% 14% 0% -12% -23% 24.3% 19.3% 16.2% 14.2% 12.7%

MRSK North Caucasus 37% 17% 0% -15% -28% 32.8% 24.7% 20.0% 17.3% 15.3%

MRSK Center & Volga 24% 11% 0% -11% -20% 23.4% 18.7% 15.8% 13.8% 12.4%

MRSK North-West 26% 12% 0% -10% -18% 21.8% 17.3% 14.5% 12.7% 11.5%

MRSK Siberia 36% 17% 0% -13% -25% 22.0% 17.2% 14.3% 12.6% 11.4%

MRSK Urals 30% 14% 0% -11% -21% 18.9% 15.2% 12.9% 11.4% 10.3%

MRSK Volga 29% 14% 0% -11% -21% 25.1% 19.5% 16.2% 14.1% 12.6%

Moscow Unified DC 9% 5% 0% -12% -23% 15.6% 14.2% 12.8% 11.0% 9.7%

Moscow City DC 9% 5% 0% -12% -23% 27.2% 22.5% 19.2% 16.1% 13.8%

Lenenergo 8% 4% 0% -12% -23% 22.9% 20.1% 17.7% 14.9% 12.9%

Tyumenenergo 1% 1% 0% -10% -20% 11.3% 10.7% 10.0% 9.0% 8.3%

Total 21.8% 17.6% 14.9% 13.0% 11.6%

Company

Year of RAB introduction

Change in target price

Tariff growth CAGR through year

of RAB introduction

-50% -25% -10% Base 10% 25% 50% -50% -25% -10% Base 10% 25% 50%

MRSK Center -47% -24% -9% 0% 9% 24% 47% 12.5% 15.1% 16.6% 17.5% 18.4% 19.7% 21.8%

MRSK South -47% -24% -9% 0% 9% 24% 47% 12.2% 14.3% 15.5% 16.2% 17.0% 18.1% 19.8%

MRSK North Caucasus -51% -26% -10% 0% 10% 26% 51% 14.8% 17.5% 19.1% 20.0% 21.0% 22.3% 24.5%

MRSK Center & Volga -43% -22% -9% 0% 9% 22% 43% 11.8% 13.9% 15.0% 15.8% 16.6% 17.6% 19.4%

MRSK North-West -44% -22% -9% 0% 9% 22% 44% 10.4% 12.5% 13.7% 14.5% 15.2% 16.3% 18.0%

MRSK Siberia -51% -25% -10% 0% 10% 25% 51% 10.2% 12.3% 13.5% 14.3% 15.0% 16.1% 17.8%

MRSK Urals -47% -23% -9% 0% 9% 23% 47% 10.0% 11.5% 12.3% 12.9% 13.4% 14.2% 15.5%

MRSK Volga -46% -23% -9% 0% 9% 23% 46% 11.7% 14.0% 15.4% 16.2% 17.0% 18.2% 20.1%

Moscow Unified DC -36% -18% -7% 0% 7% 18% 36% 10.3% 11.6% 12.3% 12.8% 13.2% 13.9% 15.0%

Moscow City DC -36% -18% -7% 0% 7% 18% 36% 15.0% 17.2% 18.4% 19.2% 20.0% 21.2% 23.0%

Lenenergo -30% -15% -6% 0% 6% 15% 30% 14.9% 16.3% 17.2% 17.7% 18.2% 19.0% 20.3%

Tyumenenergo -29% -15% -6% 0% 6% 15% 29% 8.8% 9.4% 9.8% 10.0% 10.3% 10.6% 11.2%

Total 11.3% 13.2% 14.3% 14.9% 15.6% 16.6% 18.2%

Company Change in target price Tariff growth CAGR, 2007 - 2011

DRC estimate

0% 1%

Base

2% 3% 4% 0% 1%

Base

2% 3% 4%

MRSK Center -25% -12% 0% 13% 26% 15.8% 16.7% 17.5% 18.4% 19.2%

MRSK South -27% -14% 0% 14% 29% 14.7% 15.5% 16.2% 17.0% 17.7%

MRSK North Caucasus -24% -12% 0% 12% 25% 18.4% 19.2% 20.0% 20.9% 21.7%

MRSK Center & Volga -22% -11% 0% 12% 24% 14.4% 15.1% 15.8% 16.5% 17.2%

MRSK North-West -21% -11% 0% 11% 23% 13.1% 13.8% 14.5% 15.1% 15.8%

MRSK Siberia -25% -13% 0% 13% 27% 12.9% 13.6% 14.3% 14.9% 15.6%

MRSK Urals -21% -11% 0% 11% 23% 11.9% 12.4% 12.9% 13.4% 13.9%

MRSK Volga -17% -8% 0% 9% 18% 15.0% 15.6% 16.2% 16.8% 17.5%

Moscow Unified DC -17% -9% 0% 9% 18% 11.9% 12.3% 12.8% 13.2% 13.7%

Moscow City DC -17% -9% 0% 9% 18% 17.7% 18.5% 19.2% 20.0% 20.8%

Lenenergo -16% -8% 0% 8% 17% 16.6% 17.2% 17.7% 18.3% 18.8%

Tyumenenergo -12% -6% 0% 6% 13% 9.6% 9.8% 10.0% 10.2% 10.5%

Total 13.7% 14.3% 14.9% 15.6% 16.2%

Company Change in target price Tariff growth CAGR, 2007 - 2011

Rate of RCN appreciation

-50% -25% -10% Base 10% 25% 50% -50% -25% -10% Base 10% 25% 50%

MRSK Center -4% -2% -1% 0% 1% 2% 4% 16.6% 17.0% 17.3% 17.5% 17.7% 18.0% 18.4%

MRSK South -5% -3% -1% 0% 1% 3% 5% 15.2% 15.7% 16.0% 16.2% 16.4% 16.7% 17.2%

MRSK North Caucasus 0% 0% 0% 0% 0% 0% 0% 19.6% 19.8% 19.9% 20.0% 20.1% 20.2% 20.5%

MRSK Center & Volga -7% -4% -1% 0% 1% 4% 7% 14.7% 15.2% 15.6% 15.8% 16.0% 16.4% 16.9%

MRSK North-West -6% -3% -1% 0% 1% 3% 6% 13.8% 14.1% 14.3% 14.5% 14.6% 14.8% 15.1%

MRSK Siberia -1% -1% 0% 0% 0% 1% 1% 14.0% 14.1% 14.2% 14.3% 14.3% 14.4% 14.6%

MRSK Urals -4% -2% -1% 0% 1% 2% 4% 12.4% 12.6% 12.8% 12.9% 13.0% 13.1% 13.4%

MRSK Volga -4% -2% -1% 0% 1% 2% 4% 15.6% 15.9% 16.1% 16.2% 16.3% 16.5% 16.8%

Moscow Unified DC -16% -8% -3% 0% 3% 8% 16% 10.1% 11.5% 12.3% 12.8% 13.3% 14.0% 15.2%

Moscow City DC -16% -8% -3% 0% 3% 8% 16% 15.7% 17.5% 18.6% 19.2% 19.9% 20.9% 22.4%

Lenenergo -17% -9% -3% 0% 3% 9% 17% 13.8% 15.8% 17.0% 17.7% 18.4% 19.5% 21.2%

Tyumenenergo -21% -10% -4% 0% 4% 10% 21% 8.5% 9.3% 9.7% 10.0% 10.3% 10.7% 11.4%

Total 13.7% 14.3% 14.7% 14.9% 15.2% 15.6% 16.2%

Company Change in target price

Total capex, 2H07-2010

Tariff growth CAGR, 2007 - 2011


Foreign peer comparison

Almost all MRSKs have completed consolidation (except Moscow MRSK), but they have not all

published consolidated financials yet. The financial multiples presented below are based on the

RAS financial statements of each MRSK’s regional distribution companies.

On average, Russian distribution companies currently trade at 39-52% premiums on various

earnings multiples. It thus seems the market has to some extent already priced in the transition

to the new regulatory approach and associated improvements in the financial performance of

Russian distribution companies. Nevertheless, asset-based ratios such as EV/grid length and

EV/electricity throughput are still indicative that the market heavily discounts Russian distribution

companies relative to their foreign peers.


Figure 116: Peer group, distribution companies

Source: Company data, Bloomberg, Glitnir estimates

2006 2011e 2006 2011e 2006 2011e

Cur-

rent

Tar-

get

Cur-

rent

Tar-

get 2006 2011e 2006 2011e 2006 2011e

MRSK Center Russia MRKC RU 2 191 2 303 2.5 0.9 13.1 2.0 33.3 4.6 1.5 38 60 6.3 9.8 19% 47% 10% 29% 7% 19%

MRSK South Russia n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 50 n/a 9.9 14% 41% 7% 25% 1% 16%

MRSK North Caucasus Russia MRKK RU 340 358 1.2 0.4 37.2 1.0 neg 2.1 0.7 26 60 3.4 8.0 3% 44% neg 26% neg 19%

MRSK Center and Volga Russia MRKP RU 1 583 1 600 2.0 0.8 11.7 2.0 72.1 4.7 1.4 27 42 6.4 10.1 18% 42% 10% 26% 3% 18%

MRSK North-West Russia MRKZ RU 1 063 1 103 1.6 0.7 9.3 1.8 40.9 4.0 1.1 26 50 6.8 12.9 17% 39% 9% 24% 4% 17%

MRSK Siberia Russia MRKS RU 1 635 1 768 1.7 0.7 11.8 2.0 neg 4.5 1.5 19 31 6.8 11.0 14% 36% 4% 21% neg 15%

MRSK Urals Russia MRKU RU 1 666 1 722 1.6 0.7 15.5 2.5 58.9 5.5 1.5 20 27 12.2 16.6 10% 29% 6% 18% 3% 13%

MRSK Volga Russia MRKV RU 1 304 1 325 1.5 0.6 10.1 1.4 64.2 3.0 1.2 22 55 6.3 15.9 15% 41% 7% 28% 2% 20%

Moscow Unified Dis. Co. Russia MSRS RU 2 500 2 789 3.0 1.3 10.3 2.9 23.9 7.0 1.4 41 41 37.7 38.1 29% 43% 16% 26% 11% 16%

Moscow City Dis. Co. Russia MGRS RU 1 780 1 705 4.6 1.5 12.9 2.4 18.0 6.6 2.3 47 48 28.2 28.5 36% 61% 25% 38% 27% 24%

Lenenergo Russia LSNG RU 1 754 1 635 4.2 1.5 14.9 2.7 104.3 7.3 1.4 55 47 31.4 26.9 28% 54% 9% 32% 4% 20%

Lenenergo Russia LSNGP RU

Kurganenergo Russia KRGE RU 74 89 0.5 n/a 6.0 n/a n/a n/a 0.3 22 27 3.3 4.0 9% n/a 5% n/a neg n/a

Kurganenergo Russia KRGEP RU

Tomsk Dis. Co. Russia TORS RU 111 111 1.4 n/a 11.5 n/a 403.0 n/a 1.0 18 13 7.0 5.2 13% n/a 3% n/a 0% n/a

Tomsk Dis. Co. Russia TORSP RU

Kubanenergo Russia KUBE RU 496 611 1.4 n/a 12.4 n/a 203.2 n/a 1.6 38 32 7.2 6.1 12% n/a 7% n/a 1% n/a

Russian dis. co. average 2.4 0.9 14.7 2.1 52.0 4.9 1.4 32 46 14.5 15.6 18% 43% 9% 26% 5% 18%

WA 2.6 1.0 12.8 2.2 49.7 5.4 1.5 34 45 17.1 16.8 21% 44% 11% 27% 7% 18%

Foreign distribution companies

ELMU Rt. Hungary ELMU HB 939 1 077 1.1 n/a 6.8 n/a 13.6 n/a 2.1 146 n/a 48.4 n/a 16% n/a 9% n/a 7% n/a

EMASZ Hungary EMASZ HB 409 474 1.1 n/a 8.9 n/a 19.6 n/a 2.0 163 n/a 21.3 n/a 13% n/a 5% n/a 5% n/a

Prazska EnergetikaCzech

RepublicPREN CP 1 584 1 541 2.5 n/a 11.5 n/a 20.8 n/a 3.1 266 n/a 133.5 n/a 22% n/a 17% n/a 12% n/a

Eletropaulo Metropolitana

Eletricidade de Sao

Paulo SA

Brazil ELPL6 BZ 3 664 4 029 1.0 0.8 6.1 4.0 21.4 9.0 3.6 127 134 95.3 100.0 17% 20% 13% 17% 4% 8%

Vakaru Skirstomieji TinklaiLithuania RST1L LH 853 929 2.7 n/a 12.4 n/a 94.5 n/a 1.2 252 n/a 16.3 n/a 22% n/a 3% n/a 3% n/a

CegedelLuxem-

bourg VST1L LH 1 254 1 293 3.8 n/a 11.4 n/a 57.9 n/a 2.3 278 n/a 180.1 n/a 34% n/a 10% n/a 6% n/a

International dis. co. average 2.0 9.5 38.0 2.4 205 82.5 20% 10% 6%

WA 1.8 8.6 32.8 2.8 187 96.3 20% 12% 6%

Russian Dis. Co. premium / (discount) to foreign peers 39% 49% 52% -48% -82%


P/E


P/B,

2007e

EV,

USD

mn

MCap,

USD

mn

EV / EBITDA Net marginEBIT margin

EBITDA

margin

EV / Grid

length,

USD th/km

EV /

Through-

put 2006,

USD/MWhEV/Sales


Transmission companies

Regional transmission companies are to be merged into FSK on July 1, 2008. As a result, FSK

will consolidate practically all of Russia’s transmission assets.

To value FSK we applied the same asset-based approach we used to value distribution

companies. We assumed RAB regulation would come into effect for FSK in 2012, a year later

than for distribution companies. This is in line with the RAB introduction date assumed by the

independent appraiser that evaluated FSK and transmission companies for consolidation

purposes.

To calculate FSK’s fair enterprise value we estimated RAB on the expected RAB introduction

date (January 1, 2012). Assuming the new regulatory system will provide a return on invested

capital equal to the WACC required by investors, FSK’s YE11e enterprise value should equal its

YE11e RAB. Based on our forecasts of net debt and number of shares outstanding as of YE11e,

we estimated FSK’s fair value per share by YE11. Discounting it back to present, we arrived at

the current fair value for FSK shares.

We estimated FSK’s YE11e RAB using the following formula, which is similar to the one we used

in our valuation of distribution grids:

YE11e RAB = Current DRC + Expected capex through 2011 (excluding connection

fee) – Depreciation through 2011

Depreciated replacement cost (DRC) estimate

There are RCN and DRC estimates for FSK and transmission companies available that were

prepared by an independent appraiser and reported to analysts in September 2007. We cross-

checked these estimates against data on foreign peers. The appraiser estimated an RCN for

FSK of about USD 288 000 per kilometre of grid, which is 18% below the gross book value of

fixed assets of foreign peers on a per-kilometre basis. FSK’s accumulated depreciation rate

stands at 48%, which is 6 pp above the average for the company’s foreign peers, resulting in a

DRC estimate for FSK of USD 150 000/km, 25% below the average peers’ net book value of

USD 201 000/km. This difference seems reasonable given that the power utilities sector as a

whole and Russian transmission assets in particular have been underfinanced for years. Overall,

we found the appraiser’s data provided a reasonable estimate for FSK’s DRC and incorporated it

into our valuation for FSK.

Figure 117: RCN and DRC, FSK and foreign peers


We applied a 2% annual RCN appreciation rate and a 3% annual depreciation rate to account for

changes in the economic values of assets before the RAB introduction date.

Capex

We incorporated FSK’s data on planned capex as envisaged in the company’s capex program

for 2008-2012 approved by the company’s board in May 2008. The data provided a breakdown

of the company’s capex by source of financing. When estimating RAB we did not account for

capex financed by connection fees.

Company Country BS date

PPE

cost,

USD mn

Depreci-

ation rate

PPE acc.

depr., USD

mn

PPE

net,

USD

mn

Grid

length,

km

Trans-

former

capacity,

MVA

MVA/

km

PPE

cost,

USD

thous./

km

PPE

net,

USD

thous./

km

Terna Italy Dec 31, 2007 14 646 44% -6 378 8 267 42 334 115 221 2.72 346 195

Red Electrica Spain Dec 31, 2007 10 726 34% -3 639 7 087 33 503 58 000 1.73 320 212

Transmissao Paulista Brazil Dec 31, 2007 3 364 48% -1 601 1 763 12 144 42 556 3.50 277 145

Transgrid Australia Dec 31, 2007 5 779 50% -2 915 2 864 12 442 32 575 2.62 464 230

Total / Weighted avg. 8 629 42% -3 633 4 995 25 106 76 519 2.47 351 201

Appraisal

date

RCN,

USD mn

Depreci-

ation rate

Assumed

acc. depr.,

USD mn

DRC,

USD

mn

Grid

length,

km

Trans-

former

capacity,

MVA

MVA/

km

RCN,

USD

thous./

km

DRC,

USD

thous./

km

FSK Russia Mar 31, 2007 34 674 48% 16 652 18 022 120 513 295 691 2.45 288 150


Figure 118: FSK capex through 2012

Source: FSK, Glitnir estimates

New equity issues

We also accounted for the state’s massive cash injection into FSK. We added the cash proceeds

that should be pumped into FSK through the company’s second, third, and fourth additional

share issues to FSK’s expected 2011e RAB and correspondingly increased our forecast for

number of shares outstanding. Overall, we expect that by 2012 the company will have 1 264 687

mn shares outstanding and will receive a total of USD 21.8 bn in cash proceeds from the second,

third, and fourth additional share issues (see ―Figure 28: Additional share issues‖ for details).

Discount rate

We applied a 12.4% cost of equity to discount the expected fair value of FSK as of YE11 back to

the present.

Figure 119: Cost of equity calculation, FSK


Valuation results

Figure 120: FSK target price calculation


Our target price for FSK of USD 0.0258 per share stands roughly in line with the estimate of USD

0.0248 (RUB 0.59) of fair value per share as of April 1, 2007, provided by UES’s independent

appraiser. Our target price is also 10% above FSK’s OTC forward price of USD 0.0235 per share

implied by mid-market prices of transmission companies on the RTS.

We believe the massive capex program is value-erosive for FSK shareholders because the

current regulatory system does not provide an adequate return on invested capital. We estimate

that in the absence of capex and cash inject ion from the state the target price of FSK would

stand at USD 0.0324 per share.

Source of financing, USD mn 2007 2008e 2009e 2010e 2011e 2012e

Existing equity 1 080 1 322 1 702 2 147 2 632 3 171 10 973

New equity 2 318 5 442 3 576 1 658 1 355 1 063 13 095

Debt 0 0 2 635 1 830 1 948 422 6 835

Connection fee 145 548 2 145 2 497 2 041 1 602 8 833

Total 3 542 7 312 10 058 8 133 7 975 6 258 39 736

Year Total

2008-2012

Company Market risk

Sector risk

premium

Liquidity

risk

premium

Corp. gov. risk

premium (+) /

discount (-) RROE

FSK 10.9% 1.5% 0.0% 0.0% 12.4%

USD mn

Consolidated RCN 1Q07 35 263

Consolidated RCN 1Q07 USD thous./km 316

Depreciation rate 48%

Consolidated DRC 1Q07 18 328

Consolidated DRC 1Q07, USD thous./km 164

Capex excl. connection fee 2Q07-2012 29 289

RAB YE11e 43 004

Fair EV/RAB YE11e 1.00

Net debt (+) / cash (-) YE11e -69

Fair MCap YE11e 43 073

Expected number of shares, mn 1 264 687

FV per share YE11e, USD 0.0347

Current FV per share, USD 0.0229

12m TP, USD 0.0258

Target EV*/DRC 0.58

Target EV*/km, USD thous./km 96

* On fully consolidated basis


Figure 121: Valuation without capex or state injection


Target price calculation for regional transmission companies

To estimate the target prices of Russian transmission companies, we applied the swap ratios into

FSK approved by UES and shareholders of regional transmission companies.

We assigned a 30% company-specific discount to the target prices of Kurgan, Kuban, and

Tomsk transmission companies, as shareholders of Kurgan Transmission Company have

reportedly blocked the company’s merger into FSK, and mergers of Kuban and Tomsk

transmission companies into FSK have been prohibited by the court (see ―Appendix 1: Company-

specific issues‖).There remains a possibility that shares of Kurgan, Kuban, and Tomsk

transmission companies will be converted into FSK; however, the timing of this is uncertain for

now.

Figure 122: Target price, regional transmission companies


What do our valuation assumptions imply by 2012?

Our valuation implies that the transmission tariff will grow 2.4x between 2006 and 2012, implying

a CAGR of 15% over six years. We believe the government will find this growth rate acceptable,

though high enough for it to be reluctant to allow tariffs to advance any faster, as reducing

inflation has been a priority in Russian economic policy.

According to our estimates, FSK’s top line will rise to USD 10.0 bn and EBIT margin to 59% by

2012.

Figure 123: Transmission tariff

Figure 124: FSK, revenues


USD mn

Consolidated RCN 1Q07 35 263

Depreciation rate 48%

Consolidated DRC 1Q07 18 328

RAB 2011e 14 375

Fair EV/RAB 2011e 1.0

Net debt (+) / cash (-) 2011e -12 442

Fair MCap 2011e 26 817

Expected number of shares 614 003

FV per share 2011e, USD 0.0437

Current FV per share, USD 0.0289

12m TP, USD 0.0324

Company BB ticker Share type Rating

FV per

share,

USD

12m TP,

USD

Market

price as

of Jun 19,

2008

Upside

to TP

MCap,

USD mn

EV,

USD mn

Vologda Trans. Co. VOMS RU common Hold 1.56 1.75 1.70 3% 36 n/a

Kuban Trans. Co. KNMS RU common Reduce 0.288 0.323 0.475 -32% 8 n/a

Tomsk Trans. Co. TOMS RU common Reduce 0.0102 0.0114 0.0158 -28% 59 66

Tomsk Trans. Co. TOMSP RU preferred Reduce 0.00930 0.0105 0.0135 -23%

7.7

18.3

0

5

10

15

20

2006 2012e

US

D/M

Wh

Effective tariff, USD/MWh

CAGR 15%

3.4

10.0

0

2

4

6

8

10

12

2006 2012e

US

D, b

n

Revenue, USD mn

CAGR 19%


Figure 125: FSK, EBIT margin



We tested the sensitivity of our fair value for FSK to changes in various key valuation

assumptions.

Figure 126: Sensitivity to year of introduction


Figure 127: Sensitivity to DRC estimate


Figure 128: Sensitivity to RCN appreciation rate


Foreign peer comparison

The OTC forward price of FSK is USD 0.0235 per share. The company currently trades at a 66%

discount to its foreign peers on an EV-to-grid- length basis, and 35-54% discounts based on

various financial ratios.

35%

40%

45%

50%

55%

60%

65%

0

2 000

4 000

6 000

8 000

2006 2012e

US

D, m

n

EBIT, USD mn EBIT margin, %

CAGR 29%

2010 2011

Base,

2012 2013 2014 2010 2011

Base,

2012 2013 2014

Company

FSK 20% 9% 0% -8% -14% 18.7% 16.4% 14.9% 13.3% 11.8%

Target price change

Implied tariff growth CAGR through

year of RAB introduction

-50% -25% -10% Base 10% 25% 50% -50% -25% -10% Base 10% 25% 50%

Company

FSK -19% -9% -4% 0% 4% 9% 19% 12.6% 13.8% 14.4% 14.9% 15.3% 15.9% 16.9%

Target price change Tariff growth CAGR, 2007 - 2011

0% 1%

Base,

2% 3% 4% 0% 1%

Base,

2% 3% 4%

Company

FSK -10% -5% 0% 5% 10% 13.7% 14.3% 14.9% 15.4% 16.0%

Target price change Tariff growth CAGR, 2007 - 2011


Figure 129: Peer comparison, FSK



MCap*,

USD

mn

EV*,

USD

mn

EV /

Sales

2006

EV /

EBITDA

2006

P/E

2006

P/B

2006

EV / Grid

length,

USD

thous.

/km

EV /

Through-

put 2006,

USD/

MWh

EBITDA

margin,

2006

EBIT

margin,

2006

Net

margin,

2006

Russian trans. co.

FSK n/a 12 414 10 323 3.0 5.5 n/a 2.7 86 23.0 54% 39% n/a

Vologda Trans. Co. VOMS RU 36 n/a

Kuban Trans. Co. KNMS RU 8 n/a

Tomsk Trans. Co. TOMS RU 59 66

Tomsk Trans. Co. TOMSP RU

Foreign trans. co.

Terna Rete Elettrica

Nazionale SpAItaly TRN IM 8 991 13 156 8.5 11.9 18.4 3.2 317 41.6 72% 53% 32%

Cia de Transmissao

de Energia Eletrica PaulistaBrazil

TRPL3 BZ 4 394 4 609 7.6 43.6 81.2 2.5 380 35.5 17% 5% 9%

Interconexion Electrica SALatin

AmericaISA CB 5 029 5 027 5.6 10.1 78.9 1.7 134 96.0 55% 16% 7%

Lietuvos Energija Lithuaniua LEN1L LH 1 086 1 106 3.1 16.0 159.6 1.3 166 89.6 19% 3% 2%

Red Electrica de Espana Spain REE SM 9 117 n/a n/a n/a 36.3 6.8 n/a n/a 68% 42% 21%

International trans. co. avg. 6.2 20.4 84.5 2.2 249 65.7 41% 19% 12%

WA 7.5 17.8 56.0 2.6 284 54.1 55% 34% 21%

Russian FSK premium / (discount) to foreign peers -60% -69% n/a 5% -70% -57%

* For FSK - based on OTC forward price, on fully consolidated basis



We believe FSK deserves a discount to its foreign peers both on financial and asset-based

multiples for the following reasons:

1. The late switch to a RAB model, which will provide investors with a fair return on

invested capital. According to our estimates, FSK will start earning an adequate return

on shareholders’ equity in 3.5 years.

2. Higher depreciation. FSK’s assets are depreciated to a much higher extent compared

with its peers. FSK and the Russian utilities sector as a whole have been

underfinanced for decades.

3. Inefficient capex. FSK is going to invest some USD 33.5 bn before its regulation is

switched to the RAB approach. Such capex is value-erosive for shareholders in our

view, as the current cost-based approach does not provide investors with fair return on

capital.

Independent AO-energos

We evaluated three listed independent AO-energos (Irkutskenergo, Bashkirenergo, and

Novosibirskenergo) as a sum of their generation, distribution, and transmission divisions. We

based the valuation of generation on the DCF approach we used for OGKs and TGKs, while for

transmission and distribution we used generally the same methodology as in the valuation of

FSK and the MRSKs, respectively. Therefore all the assumptions and methods discussed above

in regards to the valuation of generators and grids apply in full to the independent AO-energos.

Figure 130: Sum-of-parts valuation, independent AO-energos


Far East Energy Company

We valued Far East Energy Company as the sum of Far East Generation Company and Far East

Distribution Company. We valued Far East Generation Company with the same approach we

used for generation companies (DCF), and Far East Distribution Company with the same

approach we used for distribution companies (asset-based).

We used a DCF valuation for the isolated energy companies on a company-wide basis; our

models for these companies thus effectively incorporate retail electricity prices paid by

consumers rather than wholesale prices.

Due to technical constraints, we do not expect that electricity prices in the Far East and isolated

regions will be liberalised any time soon. We do believe, however, that growth in regulated tariffs

would imply steady improvements in the profitability of these companies. For valuation purposes

we assumed that the EBIT margin of Far East Generation Company and isolated energy

companies would increase from its current level of nearly 0% to 7% by 2011.

Assumptions implied in our models for Far East Generation Company and the isolated energy

companies other than those related to electricity tariffs are generally the same as those used in

the valuation of generation companies located in the European and Siberian parts of Russia.

Bashkirenergo Irkutskenergo Novosibirskenergo

Fair EV of generation, USD mn 2 660 7 822 1 719

Fair EV of grids, USD mn 1 133 975 572

Total Fair EV, USD mn 3 793 8 797 2 291

Net debt 2007e, USD mn - 49 - 23 - 223

Fair MCap, USD mn 3 744 8 774 2 068

Common shares outstanding, mn 1 043 4 767 14

Preferred shares outstanding, mn 50 n/a 3

FV of common share, USD 3.52 1.84 138

12m TP of common share, USD 4.04 2.14 159

Current common share price, USD 1.59 0.88 70.5

Upside to TP, common share 155% 143% 125%

FV of preferred share, USD 1.50 n/a 78.1

12m TP of preferred share, USD 1.72 n/a 89.7

Current preferred share price, USD 1.56 n/a 46.0

Upside to TP, preferred share 11% n/a 95%


Figure 131: Sum-of-parts valuation, Far East Energy Company


UES

UES, the largest Russian utility, is to be broken up on July 1, 2008. June 6, 2008, was the last

trading day of UES shares and the record date for the breakup.

Those UES shareholders who held shares in the company on June 6 will receive one of two

baskets of underlying shares depending on their voting decision at the company’s EGM on

October 26, 2007 (see section ―The reform: UES breakup‖ for details).

We estimate the target value of the ―for‖ basket of shares at USD 2.08 and USD 1.82 per UES

common and preferred shares, respectively. These values stand 92% and 96% above the last

MICEX trading quotes of UES common and preferred shares on June 6, 2008, of USD 1.08 and

USD 0.93, respectively.

Fair EV of generation, USD mn 1 841

Fair EV of grids, USD mn 527

Total Fair EV, USDm 2 368

Net debt 2007, USD mn - 842

Fair value of stake in FSK, USD mn 287

Fair MCap, USD mn 1 813

Common shares outstanding, mn 17 223

FV per share, USD 0.105

12m TP, USD 0.119

Current price, USD 0.0725

Upside to 12m TP 64%


Figure 132: UES basket indicative valuation


Number of

underlying

shares

Value at

market

prices,

USD

Target

value,

USD

Number of

underlying

shares

Value at

market

prices,

USD

Target

value,

USD

Number of

underlying

shares

Value at

market

prices,

USD

Target

value,

USD

Number of

underlying

shares

Value at

market

prices,

USD

Target

value,

USD

12m

common

TP

12m

preferred

TP

MRSK Holding ** - 1 0.2300 0.2922 1 0.1840 0.2046 1 0.2300 0.2922 1 0.1840 0.2046 0.318 0.223

Far East Energy Holding ** - 1 0.0600 0.0672 1 0.0480 0.0471 1 0.0600 0.0672 1 0.0480 0.0471 0.0672 0.0471

FSK - 10.1056 0.2375 0.2605 9.2547 0.2175 0.2386 22.7734 0.5352 0.5871 20.8559 0.4901 0.5377 0.0258

RusHydro HYDR 3.4532 0.2927 0.3786 3.1624 0.2680 0.3468 4.5042 0.3817 0.4939 4.1250 0.3496 0.4523 0.110

OGK-1 OGKA 0.9620 0.0868 0.1268 0.8810 0.0795 0.1161 0.3112 0.0281 0.0410 0.2850 0.0257 0.0376 0.132

OGK-2 OGKB 0.5008 0.0441 0.0859 0.4586 0.0404 0.0787 0.1620 0.0143 0.0278 0.1483 0.0131 0.0255 0.172

OGK-3 OGKC 0.4114 0.0478 0.0664 0.3768 0.0438 0.0608 0.1331 0.0155 0.0215 0.1219 0.0142 0.0197 0.161

OGK-4 OGKD 1.0274 0.0822 0.1707 0.9409 0.0753 0.1564 0.3323 0.0266 0.0552 0.3043 0.0243 0.0506 0.166

OGK-6 OGKF 0.5836 0.0747 0.0593 0.5345 0.0684 0.0543 0.1888 0.0242 0.0192 0.1729 0.0221 0.0176 0.102

TGK-1 TGKA 38.2332 0.0510 0.0579 35.0140 0.0467 0.0530 12.3666 0.0165 0.0187 11.3254 0.0151 0.0171 0.00151

TGK-2 TGKB 12.9829 0.0129 0.0176 11.8897 0.0118 0.0161 4.1993 0.0042 0.0057 3.8458 0.0038 0.0052 0.00136 0.000832

TGK-3 (Mosenergo) MSNG 0.3360 0.0595 0.0935 0.3077 0.0545 0.0856 0.1087 0.0192 0.0302 0.0995 0.0176 0.0277 0.278

TGK-4 TGKD 15.8655 0.0167 0.0225 14.5296 0.0153 0.0206 5.1317 0.0054 0.0073 4.6996 0.0049 0.0067 0.00142 0.000707

TGK-6 TGKF 15.3259 0.0112 0.0156 14.0355 0.0102 0.0143 4.9572 0.0036 0.0050 4.5398 0.0033 0.0046 0.00102

TGK-7 TGKG 0.3344 0.0301 0.0562 0.3062 0.0276 0.0515 0.1082 0.0097 0.0182 0.0991 0.0089 0.0166 0.168

TGK-8 TGKH 17.2625 0.0287 0.0252 15.8090 0.0263 0.0231 5.5836 0.0093 0.0082 5.1135 0.0085 0.0075 0.00146

TGK-9 TGKI 67.3347 0.0202 0.0296 61.6651 0.0185 0.0271 21.7796 0.0065 0.0096 19.9457 0.0060 0.0088 0.000439

TGK-10 * TGKJ 0.0089 0.0409 0.0589 0.0081 0.0374 0.0540 0.0029 0.0132 0.0191 0.0026 0.0121 0.0175 6.65

TGK-11 TGKK 6.1864 0.0069 0.0133 5.6655 0.0063 0.0122 2.0010 0.0022 0.0043 1.8325 0.0021 0.0039 0.00215

TGK-12 (Kuzbassenergo) KZBE 0.6991 0.0164 0.0342 0.6402 0.0150 0.0313 0.2261 0.0053 0.0111 0.2071 0.0049 0.0101 0.0490

TGK-13 (Yeniseyskaya TGK) TGKM 1.7233 0.0142 0.0341 1.5782 0.0130 0.0312 0.5574 0.0046 0.0110 0.5105 0.0042 0.0101 0.0198

TGK-14 TGKN 9.7136 0.0032 0.0049 8.8957 0.0029 0.0045 3.1419 0.0010 0.0016 2.8773 0.0009 0.0014 0.000501

InterRAO - 41.8643 0.1054 38.3394 0.0966 41.8643 0.1054 38.3394 0.0000 0.0966 0.00252

Centerenergoholding (Gazprom) ** - 1.0490 0.0715 0.0901 1.0490 0.0572 0.0901 0.0859 0.0687

Sibenergoholding (SUEK) ** - 0.9662 0.0076 0.0142 0.9662 0.0061 0.0142 0.0147 0.0118

Intergeneration (Norilsk Nickel) ** - 3.5169 0.0259 0.0360 3.5169 0.0207 0.0360 0.0102 0.0082

Value of baskets per UES share 1.47 2.08 1.31 1.82 1.52 2.00 1.348 1.767

* If adjusted for planned share split, ratios would change to:

1.4710 1.3471 0.4758 0.4357

** UES prefs holders receive preferred shares in MRSK Holding, Far East Energy Holding,

Centerenergoholding, Sibenergoholding and Intergeneration

Voting AGAINST issue no. 1 on EGM agenda

("AGAINST basket")

Per UES common Per UES preferred

Company Ticker

Voting FOR issue no. 1 on EGM agenda or not participating

("FOR basket")

Per UES common Per UES preferred


We have detailed the valuation of MRSK Holding, Far East Energy Holding, and InterRAO, the

entities that will be received by former UES shareholders. As none of these three entities are

listed, we are not giving an investment recommendation; we provide target prices for informational

purposes only.

UES will spin off MRSK Holding and Far East Energy Holding on a pro-rata basis, meaning a

UES shareholder will receive one common share of MRSK Holding and one common share of Far

East Energy Holding for each common share of UES, and one preferred share of each of these

two companies for one preferred share of UES. Thus MRSK Holding and Far East Energy

Holding will each have the same number of shares outstanding as UES.

MRSK Holding

MRSK Holding will be created on the UES breakup date of July 1, 2008. In accordance with the

breakup balance, MRSK Holding will receive all of UES’s stakes in regional distribution

companies and some other entities (mainly project institutions), as well as a portion of fixed

assets from UES’s balance sheet. The largest asset that will be included in MRSK Holding

besides electricity distribution companies is a stake in Moscow Heat Distribution Company.

Our target price for MRSK Holding is based on our valuation of MRSKs.

Figure 133: MRSK Holding valuation


We applied a holding discount of 15% to MRSK Holding. We believe the company does not

deserve a discount any higher than this given that all of its main assets operate in a single

segment of the industry.

Far East Energy Holding

Far East Energy Holding will be created on the UES breakup date of July 1. In accordance with

the breakup balance sheet, UES will contribute its stakes in Far East Energy Company, isolated

energy companies, certain supply companies, and a portion of its fixed assets to the charter

capital of Far East Energy Holding.

Stakes in MRSKs at fair value Stake, % USD mn

MRSK Center 50.23% 1 578

MRSK South 50.62% 681

MRSK North Caucasus 58.25% 427

MRSK Center and Volga 50.40% 1 142

MRSK North-West 55.40% 1 020

MRSK Siberia 52.80% 1 212

MRSK Urals 50.10% 924

MRSK Volga 67.61% 2 028

Moscow Unified Dist. Co. 50.90% 1 144

Moscow City Dist. Co. 50.90% 828

Lenenergo 45.19% 636

Tyumenenergo 100.00% 1 196

Total stakes in MRSKs, USD mn 12 815

Stake in Moscow Heat Distribution

at actual sales price, USD mn 576

Stakes in engineering centers at

actual sales price, USD mn 696

Fair holding discount 15%

Total Fair EV, USD mn 11 974

Net debt, USD mn -8

Total Fair MCap, USD mn 11 982


Preferred shares outstanding, mn 2 075

Fair discount of preferred shares 30%

FV per common share, USD 0.282

FV per preferred share, USD 0.197

TP common share, USD 0.318

TP preferred share, USD 0.223


Our target price for Far East Energy Holding is based on our valuation of Far East Energy

Company and isolated energy companies. We also accounted for the value of stakes in supply

companies at the actual prices at which UES auctioned them (see details in "Privatisation: Supply

company auctions"); for those that have not yet been sold we used an EV/electricity sales of USD

6.6/MWh, which is the average multiple implied in the actual sales prices of supply companies

auctioned to date.

Figure 134: Sum-of-parts valuation, Far East Energy Holding


InterRAO

InterRAO is an electricity importer and exporter that controls various generation and distribution

assets in Russia and abroad.

We valued InterRAO on a fully consolidated basis (i.e. we incorporated Sochi TPP, North-West

CHP, Kaliningrad CHP-2, and Ivanovo CCGT). We evaluated these four power plants with the

DCF method, and InterRAO’s international business at an EV/EBITDA of 8.3x (a 30% discount to

foreign peers).

Figure 135: Sum-of-parts valuation, InterRAO sum


Stakes in Far East and isolated utilities at fair value:

Stake, % USD mn

Far East Energy Company 50.92% 923

Kamchatskenergo 98.68% 55

Magadanenergo 49.00% 22

Sakhalinenergo 49.00% 15

Yakutskenergo 47.39% 216

Total 1 230

Stakes in 39 supply companies at actual sales price 899

Stakes in 5 supply companies at USD 6.6/MWh 400

Total Fair EV, USD mn 2 529

Net debt, USD mn -2

Total Fair MCap, USD mn 2 531




FV per common share, USD 0.0596

FV per preferred share, USD 0.0417

TP common share, USD 0.0672

TP preferred share, USD 0.0471

USD mn

Kaliningrad CHP-2 385

North-West CHP 725

Sochi TPP 78

Ivanovo CCGT 415

Total four power plants merged in 2008 1 602

Assets consolidated in IFRS 2006 at EV/EBITDA of 8.3x 1 672

50% stake in Ekibastuz GRES-2 at carrying value 101

Fair EV 3 375

Net debt, 2007e 109

Fair MCap 3 267

Common shares outstanding (expected after consolidation of the

four power plants), mn 1 470 538

FV common, USD 0.00222

TP common, USD 0.00252


Appendix 1: Company-specific issues

OGK-1

In February 2008, OGK-1 and TNK-BP signed a preliminary agreement on the establishment of a

joint venture. By the terms of the agreement, OGK-1 plans to contribute its two 800 MW blocks at

Nizhevartovskaya GRES to the venture, while TNK-BP will contribute USD 320 mn in cash. The

cash is to be used to construct a third 800 MW power block at Nizhevartovskaya GRES, which

will be fuelled with associated gas from TNK-BP’s facilities. The agreement envisages that TNK-

BP will receive a 25% stake in the venture and will have the option to acquire a stake of up to

50% minus one share in the company after the construction of the new power block is completed

in 2010. OGK-1 and TNK-BP also plan to sign a long-term (15+ years) agreement on the supply

of gas to all three blocks and the supply of electricity from the new block to TNK-BP’s facilities.

The announced terms of the deal imply that TNK-BP will acquire a 25% stake in

Nizhevartovskaya GRES, one of the best power plants in Russia in terms of quality of assets, at

an EV/capacity of USD 600/kW. Under our assumptions on market-based gas and electricity

prices, we estimate Nizhevartovskaya GRES’s target EV/capacity at USD 1145/kW, which is 91%

above the price offered by TNK-BP. Unless TNK-BP supplies gas to the plant at prices

significantly below the market, we believe the joint venture presents value-dilution risks to OGK-1

shareholders.

As the deal has not yet been finalized (and we consider there is a chance it will be cancelled or

amended when UES sells its controlling stake in OGK-1 to a strategic investor), and as the terms

of the long-term gas- and electricity-supply contracts in regards to Nizhevartovskaya GRES are

not clear, we have not accounted for the joint venture in our valuation of OGK-1. Instead, we

currently value the station as 100%-owned by OGK-1; however we added a 1.5% company-

specific adjustment to OGK-1’s cost of equity to account for the risks associated with the joint

venture.

Dispute with Rosneft

In 2006, the Rosneft subsidiary Neft-Activ acquired former Yukos assets, including stakes in a

number of power companies. These power companies were undergoing the restructuring

process being consolidated into TGKs, MRSKs, and FSK.

Restructuring of Rosneft’s power assets


A former shareholder of the power companies (Yukos) had previously blocked the consolidation

of Tomskenergo into TGK-11 and the merger of Kuban Generation Company into TGK-8. As a

result, TGK-8 was formed as a holding owning a 67% stake in Kuban Generation Company.

In February 2008, Neft-Activ filed a lawsuit against Tomskenergo’s consolidation into TGK-11,

reportedly because Neft-Activ was not notified of the EGM. However, UES stated that all the

procedures related to TGK-11’s formation were completed in compliance with all applicable laws.

Former YUKOS power assets

acquired by Rosneft

Generation

Kuban Gen. Co.

Tomskenergo

TGK-8

TGK-11

merger blocked by YUKOS

merger

Distribution

Kubanenergo

Tomsk Dist. Co.

MRSK South

MRSK Siberia

merger

merger

Transmission

Kuban Trans. Co.

Tomsk Trans. Co.

FSK

merger


In the same month, Neft-Activ also filed several lawsuits regarding the mergers of Kubanenergo

and Tomsk Distribution Company into MRSK South and MRSK Siberia, respectively, and the

consolidation of Kuban and Tomsk Transmission Companies into FSK.

Government bodies took the following measures as a result of the lawsuits:

As a complementary measure, the court prohibited additional share issues of TGK-11

that aimed to finance the generation company’s investment program and facilitate the

UES breakup.

Consolidation of Tomsk and Kuban Transmission Companies into FSK was stopped by

the Federal Securities Commission.

The court’s first decision came on June 6, 2008, when it ruled the merger of Kubanenergo into

MRSK South was invalid (i.e. it ruled in favour of Rosneft) because it found ―serious violations of

shareholders’ rights.‖ The court’s second decision, which was related to the merger of Kuban

Transmission Company into FSK, came on June 20, 2008, and also ruled in favour of Rosneft;

the merger was effectively considered invalid. Kubanenergo and Kuban Transmission Company

had 30 days from the court decisions to file an appeal.

Following the court’s rulings on Kubanenergo and Kuban Transmission Company we consider

there is a certain chance the consolidation procedures of the other companies involved will be

stopped or reversed.

Scheduled court hearings of lawsuits

Source: Interfax

Transfer pricing risks of RusHydro, Irkutskenergo, and Krasnoyarsk GES

Significant volumes of electricity supplied by certain hydroelectric plants of RusHydro,

Irkutskenergo, and Krasnoyarsk GES are consumed by Rusal’s aluminium smelters.

Since 2006 RusHydro has been considering the possibility of signing long-term electricity supply

contracts with Rusal. At the beginning of 2008 RusHydro negotiated with Rusal the main

conditions of the contracts, which the media reported as the following:

Sayano-Shushenskaya GES is to be a supplier, while Sayanogorsk, Khakass and

Novokuznetsk aluminium smelters are to be consumers of electricity.

RusHydro estimated that contracts will cover about 50-60% of Sayano-

Shushenskaya GES’s output, which is about 10-15% of RusHydro’s total electricity

production.

Contracts are 8-12 years in length.

The price of contacts will be higher than a regulated tariff and lower than the

market price. According to Interfax, the price of the contracts can be as low as

USD 21/MWh.

RusHydro had planned to call an EGM on June 20, at which it had planned to approve contracts

with Rusal. However on May 30, RusHydro’s board cancelled the EGM reportedly because there

was no uniform opinion on the issue among board members (state representatives were

reportedly against the contracts).

While the EGM was cancelled, we do not rule out that in the future RusHydro may sign some

power supply contracts at prices significantly below the market.

Such transfer pricing risks are even higher for Irkutskenergo and Krasnoyarsk GES, about 48%

and 68% of which, respectively, are controlled by entities affiliated with Rusal.

Company Date

Tomskenergo/TGK-11 Jul 10, 2008

Tomsk Transmission Company Jun 23, 2008

Tomsk Distribution Company Not available


Appendix 2: Selected financials, distribution companies


2006 2011e CAGR 2006 2011e CAGR 2006 2011e CAGR 2006 2011e 2006 2011e CAGR 2006 2011e

MRSK Center 937 2 449 21% 176 1 158 46% 91 698 50% 19% 47% 66 473 48% 7% 19%

MRSK South 825 2 040 20% 119 843 48% 60 501 53% 14% 41% 12 324 94% 1% 16%

MRSK North Caucasus 291 844 24% 10 367 107% - 12 221 n/a 3% 44% - 7 159 n/a -3% 19%

MRSK Center and Volga 782 1 898 19% 137 805 42% 75 501 46% 18% 42% 22 338 73% 3% 18%

MRSK North-West 684 1 567 18% 119 609 39% 61 373 44% 17% 39% 26 268 59% 4% 17%

MRSK Siberia 1 070 2 430 18% 150 870 42% 47 511 61% 14% 36% - 98 360 n/a -9% 15%

MRSK Urals 1 080 2 424 18% 111 697 44% 60 434 48% 10% 29% 28 303 61% 3% 13%

MRSK Volga 896 2 213 20% 131 915 48% 66 610 56% 15% 41% 20 439 85% 2% 20%

Moscow Unified Dist. Co. 937 2 194 19% 270 948 29% 153 570 30% 29% 43% 104 357 28% 11% 16%

Moscow City Dist. Co. 371 1 149 25% 132 702 40% 94 435 36% 36% 61% 99 270 22% 27% 24%

Lenenergo 387 1 122 24% 109 604 41% 35 356 59% 28% 54% 16 223 70% 4% 20%

Tyumenenergo 890 1 756 15% 145 429 24% 99 315 26% 16% 24% 64 195 25% 7% 11%

Total 9 149 22 085 19% 1 610 8 949 41% 830 5 525 46% 18% 41% 351 3 709 60% 4% 17%

EBITDA, USD mn EBIT, USD mnRevenues, USD mn

Company

Net marginEBITDA margin Net income, USD mn


Appendix 3: Company profiles

In this report, current prices are taken as of June 19, 2008.

01. OGK-1 ................................................................................................................................................................................................................ 106 02. OGK-2 ................................................................................................................................................................................................................ 109 03. OGK-3 ................................................................................................................................................................................................................ 112 04. OGK-4 ................................................................................................................................................................................................................ 115 05. OGK-5 ................................................................................................................................................................................................................ 118 06. OGK-6 ................................................................................................................................................................................................................ 121 07. TGK-1 ................................................................................................................................................................................................................. 124 08. TGK-2 ................................................................................................................................................................................................................. 127 09. Mosenergo (TGK-3) ................................................................................................................................................................................................... 130 10. TGK-4 ................................................................................................................................................................................................................. 133 11. TGK-5 ................................................................................................................................................................................................................. 136 12. TGK-6 ................................................................................................................................................................................................................. 139 13. TGK-7 ................................................................................................................................................................................................................. 142 14. TGK-8 ................................................................................................................................................................................................................. 145 15. TGK-9 ................................................................................................................................................................................................................. 148 16. TGK-10 ............................................................................................................................................................................................................... 151 17. TGK-11 ............................................................................................................................................................................................................... 154 18. Kuzbassenergo (TGK-12) ................................................................................................................................................................................... 157 19. TGK-13 ............................................................................................................................................................................................................... 160 20. TGK-14 ............................................................................................................................................................................................................... 163 21. Bashkirenergo ..................................................................................................................................................................................................... 166 22. Irkutskenergo ...................................................................................................................................................................................................... 168 23. Novosibirskenergo .............................................................................................................................................................................................. 170 24. RusHydro ............................................................................................................................................................................................................ 172 25. Krasnoyarsk GES ............................................................................................................................................................................................... 175


OGK-1

Strengths Above-average electricity load factor

6-month performance

Assets

New investment projects

Fuel mix Ownership structure

2007e 2011e 2007e 2008e

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

OGK-1 RTS Index RTS Electric Utilities Index

Plant Region

Installed

electric

capacity,

MW

Installed heat

capacity,

Gcal/h

Electricity

generated,

GWh

Heat sales,

k GCal

Permskaya GRES Perm 2 400 420 14 252 243

Verkhnetagilskaya GRES Sverdlov 1 497 464 7 362 161

Iriklinskaya GRES Orenburg 2 430 121 10 207 101

Kashirskaya GRES Moscow 1 580 399 6 426 302

Nizhnevartovskaya GRES Khanty-Mansiysk 1 600 758 11 635 186

Urengoyskaya GRES Yamalo-Nenetsk 24 410 192 60

OGK-1 total 9 531 2 572 50 075 1 053

2007

Plant Project Date

New

electric

capacity,

MW

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Permskaya GRES new 800 MW CCGT 4th unit 2010 800 gas 869 38

Verkhnetagilskaya GRES new 330 MW CCGT 2011 330 gas 367 - 64

Kashirskaya GRES upgrade of 330 MW 3rd unit 2009 330 coal 391 - 50

Nizhnevartovskaya GRES new 800 MW CCGT 3rd unit 2010 800 gas 738 430

Urengoyskaya GRES new 450 MW CCGT 2011 450 gas 489 224

Gas92%

Coal7%

Fuel oil1%

Gas78%

Coal21%

Fuel oil1%

UES92%

Other minorities

8%

Strategic shareholder

75%

Other minorities

25%

OGK-1


Financials

Financial ratios

Operational data

USD mn 2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Balance sheetFixed assets 973 1 204 2 641 3 541 4 034 4 077 4 021 4 040 4 058 4 073 4 095 4 123 4 158 4 202 4 266

Non-cash WC 92 158 127 140 176 159 175 203 223 232 250 269 290 315 340

LT investments

Equity 900 1 040 1 166 1 363 2 008 2 594 3 207 4 020 5 081 6 171 7 342 8 604 9 961 11 434 13 025

Minority interest 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Net debt (+) or cash (-) 32 199 1 476 2 198 2 084 1 527 875 110 - 914 -1 979 -3 112 -4 326 -5 627 -7 031 -8 534

Other LT liabilities (+) or assets (-) 133 123 126 121 119 116 114 114 114 114 114 114 114 114 114

Income statement*Revenues 1 012 1 297 1 767 2 301 3 319 3 571 3 923 4 564 5 007 5 216 5 602 6 036 6 506 7 059 7 622

Electricity 966 1 256 1 715 2 240 3 252 3 496 3 837 4 468 4 903 5 105 5 484 5 912 6 376 6 921 7 473

Heat 16 18 25 32 38 45 54 64 70 76 80 85 90 96 106

Other 30 23 27 28 29 30 31 33 34 36 37 38 40 42 43

Cost of sales - 939 -1 176 -1 614 -1 954 -2 408 -2 723 -3 025 -3 466 -3 580 -3 750 -4 027 -4 342 -4 685 -5 084 -5 490

Fuel costs - 605 - 794 -1 163 -1 391 -1 672 -1 893 -2 146 -2 540 -2 598 -2 714 -2 936 -3 191 -3 470 -3 802 -4 136

D&A - 38 - 58 - 82 - 134 - 178 - 214 - 221 - 231 - 241 - 252 - 263 - 275 - 287 - 300 - 315

Fixed costs - 296 - 324 - 370 - 428 - 558 - 616 - 658 - 695 - 740 - 783 - 829 - 877 - 928 - 982 -1 039

EBITDA 111 179 235 481 1 089 1 062 1 119 1 329 1 669 1 718 1 837 1 968 2 108 2 275 2 448

EBIT 73 121 153 347 911 848 898 1 098 1 427 1 466 1 574 1 694 1 821 1 974 2 133

EBT 71 113 133 327 892 829 880 1 080 1 409 1 448 1 556 1 675 1 803 1 956 2 115

Net income 54 86 101 249 678 630 669 821 1 071 1 100 1 183 1 273 1 370 1 487 1 607

EBITDA margin 11% 14% 13% 21% 33% 30% 29% 29% 33% 33% 33% 33% 32% 32% 32%

EBIT margin 7% 9% 9% 15% 27% 24% 23% 24% 29% 28% 28% 28% 28% 28% 28%

Net margin 5% 7% 6% 11% 20% 18% 17% 18% 21% 21% 21% 21% 21% 21% 21%

* Non-recurring items and electricity trading activities excluded

Cash flow statementChange in WC - 37 - 48 35 - 19 - 39 14 - 19 - 29 - 20 - 9 - 17 - 20 - 21 - 25 - 25

OCF 42 91 237 383 836 877 889 1 041 1 311 1 361 1 446 1 547 1 654 1 780 1 915

Net capex - 64 - 181 -1 475 -1 161 - 746 - 336 - 242 - 250 - 259 - 268 - 284 - 303 - 322 - 345 - 379

Acquisitions/divestments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 63 - 181 -1 475 -1 161 - 746 - 336 - 242 - 250 - 259 - 268 - 284 - 303 - 322 - 345 - 379

Equity raised/bought back 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Change in debt 24 126 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 6 85 - 20 - 20 - 19 - 19 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18

Net CF - 27 - 5 -1 258 - 797 72 522 629 773 1 033 1 075 1 144 1 226 1 314 1 417 1 517

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 3.3 2.4 1.8 1.3 1.2 1.1 0.9 0.8 0.8 0.8 0.7 0.6 0.6 0.6

EV/EBITDA 23.6 18.0 8.8 3.9 4.0 3.8 3.2 2.5 2.5 2.3 2.1 2.0 1.9 1.7

P/E 47.0 39.8 16.2 5.9 6.4 6.0 4.9 3.8 3.7 3.4 3.2 2.9 2.7 2.5

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Electric capacity, MW 9 531 9 531 9 531 9 861 11 761 11 911 12 241 12 241 12 241 12 241 12 241 12 241 12 241 12 241 12 241

Electricity sales, GWh 45 048 47 752 51 246 52 971 61 324 60 159 57 938 58 105 58 521 58 792 61 360 64 121 66 947 70 337 73 428

Load factor (electricity) 57% 60% 64% 64% 62% 61% 57% 57% 57% 58% 60% 63% 66% 69% 72%

Heat capacity, Gcal/h 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572 2 572

Heat sales, thous. Gcal 1 043 1 053 1 135 1 217 1 299 1 381 1 463 1 545 1 627 1 710 1 792 1 875 1 958 2 041 2 124

Load factor (heat) 5% 5% 5% 5% 6% 6% 6% 7% 7% 8% 8% 8% 9% 9% 9%

Total effective electricity price,

USD/MWh 21 26 33 42 53 58 66 77 84 87 89 92 95 98 102

Fuel cost, USD/MWh 13 17 23 26 27 31 37 44 44 46 48 50 52 54 56

EBITDA/kW, USD 12 19 25 49 93 89 91 109 136 140 150 161 172 186 200

OGK-1


DCF

12m target price

12m target EV/capacity

Valuation

USD mn 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EBIT 153 347 911 848 898 1 098 1 427 1 466 1 574 1 694 1 821 1 974 2 133

Tax on EBIT - 37 - 83 - 219 - 204 - 216 - 264 - 343 - 352 - 378 - 406 - 437 - 474 - 512

After-tax EBIT 116 264 692 644 683 834 1 085 1 114 1 197 1 287 1 384 1 500 1 621

Depreciation 82 134 178 214 221 231 241 252 263 275 287 300 315

Capex -1 475 -1 161 - 746 - 336 - 242 - 250 - 259 - 268 - 284 - 303 - 322 - 345 - 379

Change in WC 35 - 19 - 39 14 - 19 - 29 - 20 - 9 - 17 - 20 - 21 - 25 - 25

FCFF -1 243 - 782 86 536 643 787 1 047 1 089 1 158 1 239 1 328 1 431 1 531

WACC 12.8%

Terminal growth 2.0%

NPV of cash flow 2 155

NPV of terminal value 3 168

Fair EV 5 323

Net debt 2007 - 199

Minority interest 0

Fair MCap 5 124

FV of common share, USD 0.115

Upside to FV 27%

12m TP, USD 0.132

Upside to TP 46%

Dividend yield 0.8%

Expected total return over 12m 47%


Shares outstanding, mn 44 643

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 0.166 0.177 0.191 0.209 0.231

11.8% 0.140 0.148 0.159 0.171 0.187

12.8% 0.118 0.125 0.132 0.142 0.153

13.8% 0.100 0.105 0.111 0.118 0.126

14.8% 0.085 0.089 0.094 0.099 0.105

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 784 835 899 979 1 082

11.8% 664 703 750 807 879

12.8% 565 595 630 672 724

13.8% 483 506 533 564 603

14.8% 414 432 452 476 505

Terminal growth

Plant Electricity Heat Total USD/kW

Permskaya GRES 1 635 10 1 645 685 43 1 688 703

Verkhnetagilskaya GRES 766 - 3 764 510 - 72 691 462

Iriklinskaya GRES 1 040 4 1 044 430 0 1 044 430

Kashirskaya GRES 496 11 507 321 - 56 451 285

Nizhnevartovskaya GRES 1 350 - 3 1 346 842 485 1 831 1 145

Urengoyskaya GRES - 5 58 53 2 194 253 305 12 727

OGK-1 total 5 282 76 5 359 562 652 6 011 631

12m target EV, USD mn

Existing assets New

projects Total USD/kW


OGK-2


Coal plants in European Russia

Below-average effective fuel price

Weaknesses Above-average fuel burn rate

Gazprom's corporate governance

6-month performance

Assets



2007e 2011e 2007e 2008e

-50%

-40%

-30%

-20%

-10%

0%

10%

20%


Plant Region

Installed

electric

capacity

2007, MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Pskovskaya GRES Pskov 430 121 1 735 54

Serovskaya GRES Sverdlov 526 220 3 087 102

Stavropolskaya GRES Stavropol 2 400 200 9 704 66

Surgutskaya GRES Khanty-Mansiysk 3 280 958 24 469 1 643

Troitskaya GRES Chelyabinsk 2 059 315 9 026 473

OGK-2 total 8 695 1 814 48 022 2 338

Plant Project

Completion

date

New electric

capacity,

MW Fuel type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Serovskaya GRES upgrade, 2x330 MW turbines 2012 660 coal 960 12

Stavropolskaya GRES new 2x400 MW CCGT 2011 800 gas 886 -67

Troitskaya GRES new 2x660 MW turbines 2011 1 320 coal 1886 224

Gas75%

Coal24%

Fuel oil

1%

Gas63.7%

Coal35.8%Fuel

oil

0.5%

UES66%

Gazprom12%

Westmead Limited

4%Other

minorities

18%

Gazprom57%

Westmead Limited

4%

Other minorities39%

OGK-2


Financials

Financial ratios

Operational data

USD mn 2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e


Non-cash WC 89 94 105 114 122 131 163 190 206 214 232 252 269 283 298

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 497 1 484 1 494 1 533 1 761 2 226 2 860 3 724 4 788 5 871 7 038 8 308 9 657 11 051 12 486


Net debt (+) or cash (-) 154 - 393 370 1 246 1 854 2 023 1 767 947 - 87 -1 150 -2 279 -3 499 -4 794 -6 136 -7 517


Income statement*Revenues 894 1 050 1 370 1 779 2 219 2 948 3 654 4 272 4 628 4 804 5 197 5 649 6 033 6 350 6 684

Electricity 872 1 020 1 336 1 737 2 171 2 893 3 590 4 199 4 553 4 726 5 116 5 565 5 946 6 259 6 588

Heat 18 24 29 36 42 49 58 66 68 71 74 76 79 83 87

Other 4 5 6 6 6 6 6 7 7 7 8 8 8 9 9

Cost of sales - 910 -1 062 -1 375 -1 620 -1 851 -2 259 -2 730 -3 100 -3 188 -3 340 -3 620 -3 935 -4 214 -4 471 -4 750

Fuel costs - 600 - 705 - 955 -1 124 -1 256 -1 543 -1 898 -2 214 -2 250 -2 351 -2 578 -2 836 -3 054 -3 248 -3 459

D&A - 31 - 41 - 66 - 104 - 147 - 192 - 219 - 237 - 247 - 258 - 269 - 281 - 294 - 308 - 322

Fixed costs - 278 - 316 - 354 - 392 - 447 - 524 - 614 - 649 - 691 - 731 - 774 - 818 - 866 - 916 - 969

EBITDA 12 23 56 257 509 875 1 136 1 402 1 680 1 715 1 838 1 987 2 105 2 178 2 246

EBIT - 20 - 17 - 11 153 362 683 917 1 165 1 433 1 457 1 569 1 705 1 811 1 870 1 925

EBT - 30 - 37 - 31 133 342 664 898 1 146 1 414 1 439 1 550 1 687 1 792 1 852 1 906

Net income - 31 - 37 - 31 101 260 504 683 871 1 075 1 093 1 178 1 282 1 362 1 407 1 448

EBITDA margin 1% 2% 4% 14% 23% 30% 31% 33% 36% 36% 35% 35% 35% 34% 34%

EBIT margin neg neg neg 9% 16% 23% 25% 27% 31% 30% 30% 30% 30% 29% 29%

Net margin neg neg neg 6% 12% 17% 19% 20% 23% 23% 23% 23% 23% 22% 22%


Cash flow statementChange in WC - 59 1 - 9 - 14 - 9 - 12 - 34 - 28 - 16 - 8 - 18 - 20 - 17 - 14 - 15

OCF - 53 33 54 211 418 703 886 1 099 1 325 1 362 1 448 1 561 1 657 1 719 1 774

Net capex - 37 - 419 - 797 -1 101 -1 036 - 892 - 647 - 252 - 262 - 271 - 290 - 312 - 331 - 346 - 360


ICF - 37 - 418 - 796 -1 100 -1 035 - 891 - 646 - 251 - 261 - 270 - 289 - 311 - 330 - 345 - 359


Change in debt 157 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 119 901 - 21 - 21 - 20 - 20 - 20 - 20 - 20 - 20 - 20 - 20 - 20 - 20 - 20

Net CF 29 516 - 763 - 910 - 638 - 208 220 828 1 044 1 073 1 140 1 231 1 308 1 355 1 395

2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.4 1.8 1.4 1.1 0.8 0.7 0.6 0.5 0.5 0.5 0.4 0.4 0.4 0.4

EV/EBITDA 107.5 44.8 9.7 4.9 2.8 2.2 1.8 1.5 1.5 1.4 1.3 1.2 1.1 1.1

P/E neg neg 28.5 11.1 5.7 4.2 3.3 2.7 2.6 2.4 2.2 2.1 2.0 2.0

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 16% 15% 15% 15% 15% 15% 15% 16% 16% 16% 16% 16% 16% 17% 17%


USD/MWh19 22 29 38 48 58 65 75 81 84 86 88 91 94 97

Fuel cost, USD/MWh 13 16 21 24 28 31 34 40 40 42 43 45 47 49 51

EBITDA/kW, USD 1 3 6 30 56 88 100 124 148 151 162 175 186 192 198

OGK-2


DCF

12m target price


Valuation


EBIT - 11 153 362 683 917 1 165 1 433 1 457 1 569 1 705 1 811 1 870 1 925

Tax on EBIT 3 - 37 - 87 - 164 - 220 - 280 - 344 - 350 - 377 - 409 - 435 - 449 - 462

After tax EBIT - 8 116 275 519 697 886 1 089 1 107 1 192 1 296 1 376 1 421 1 463

Depreciation 66 104 147 192 219 237 247 258 269 281 294 308 322

Capex - 797 -1 101 -1 036 - 892 - 647 - 252 - 262 - 271 - 290 - 312 - 331 - 346 - 360

Change in WC - 9 - 14 - 9 - 12 - 34 - 28 - 16 - 8 - 18 - 20 - 17 - 14 - 15

FCFF - 747 - 894 - 623 - 193 234 842 1 058 1 087 1 154 1 245 1 322 1 369 1 409

WACC 12.5%




Fair EV 4 495

Net debt 2007e 393

Minority interest 0

Fair MCap 4 888


Upside to FV 70%

12m TP, USD 0.172

Upside to TP 95%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 0.215 0.230 0.250 0.274 0.307

11.5% 0.180 0.192 0.206 0.224 0.246

12.5% 0.152 0.161 0.172 0.184 0.200

13.5% 0.129 0.136 0.144 0.153 0.165

14.5% 0.109 0.115 0.121 0.128 0.137

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 740 798 870 961 1 080

11.5% 613 657 709 773 855

12.5% 510 543 581 629 687

13.5% 424 449 479 514 556

14.5% 352 372 394 421 453

Terminal growth

Electricity Heat Total USD/kW

Pskovskaya GRES 136 1 137 317 13 150 348

Serovskaya GRES 167 - 2 165 314 - 75 90 170

Stavropolskaya GRES 679 0 679 283 0 679 283

Surgutskaya GRES 2 374 22 2 396 730 0 2 396 730

Troitskaya GRES 1 488 6 1 494 726 252 1 746 848

OGK-2 total 4 845 26 4 870 560 190 5 060 582

Plant


Existing assets New

project Total USD/kW


OGK-3

Strengths Coal plants in European Russia

Weaknesses Below-average electricity load factor

Above-average fuel burn rate

6-month performance

Assets



2007e 2011e 2007e 2008e

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Plant Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Kostromskaya GRES Kostroma 3 600 450 13 357 172

Gusinoozerskaya GRES Buryatiya 1 100 221 4 170 210

Pechorskaya GRES Komi 1 060 387 3 648 267

Kharanorskaya GRES Chita 430 128 2 335 106

Cherepetskaya GRES Tula 1 425 94 3 257 180

Yuzhnouralskaya GRES Chelyabinsk 882 395 5 343 350

OGK-3 total 8 497 1 675 32 111 1 285

Plant Project name

Completion

date

New

electric

capacity,

MW Fuel type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Gusinoozerskaya GRES upgrade of 180 MW 4th unit to 210 MW 2011 210 coal 300 - 55

Kharanorskaya GRES new 225 MW 3rd unit 2011 225 coal 322 - 25

Cherepetskaya GRES new 2x225 MW turbines 2012 450 coal 653 - 115

Yuzhnouralskaya GRES reconstruction and upgrade, 580 MW 2012 580 gas 644 49

Gas59%

Coal38%

Fuel oil3%

Gas56%

Coal41%Fuel

oil3%

UES26%

Norilsk Nickel65%

Other minorities

9%

Norilsk Nickel80%

Other minorities

20%

OGK-3


Financials

Financial ratios

Operational data



Non-cash WC 72 132 98 96 86 79 108 123 136 142 153 167 189 213 239

LT investments 5 6 6 6 6 6 6 6 6 6 6 6 6 6 6

Equity 579 4 158 4 456 4 503 4 617 4 741 5 111 5 672 6 408 7 159 7 956 8 826 9 818 10 947 12 204


Net debt (+) or cash (-) 127 -3 134 -2 936 -2 464 -2 062 -1 879 -2 232 -2 781 -3 507 -4 256 -5 043 -5 891 -6 842 -7 910 -9 092


Income statement*Revenues 758 988 1 321 1 546 1 596 1 767 2 422 2 750 3 052 3 184 3 423 3 754 4 233 4 789 5 368

Electricity 731 948 1 281 1 498 1 542 1 707 2 355 2 675 2 974 3 102 3 338 3 667 4 144 4 696 5 273

Heat 19 23 21 27 33 38 44 51 53 56 58 59 60 61 63

Other 8 17 20 21 22 22 23 24 25 26 27 28 30 31 32

Cost of sales - 756 - 909 -1 213 -1 397 -1 478 -1 631 -1 956 -2 149 -2 220 -2 330 -2 509 -2 744 -3 060 -3 434 -3 843

Fuel costs - 461 - 542 - 799 - 926 - 946 -1 027 -1 272 -1 428 -1 457 -1 526 -1 662 -1 850 -2 118 -2 440 -2 793

D&A - 40 - 48 - 67 - 94 - 125 - 157 - 169 - 176 - 183 - 191 - 198 - 207 - 216 - 226 - 237

Fixed costs - 254 - 318 - 347 - 377 - 406 - 447 - 515 - 544 - 580 - 613 - 649 - 687 - 726 - 769 - 813

EBITDA 46 129 177 244 245 295 637 779 1 018 1 047 1 114 1 220 1 392 1 583 1 764

EBIT 5 81 110 150 120 138 468 603 834 856 916 1 013 1 176 1 357 1 527

EBT - 2 147 264 303 268 283 611 745 977 998 1 058 1 155 1 318 1 499 1 670

Net income - 2 112 201 230 204 215 464 566 742 759 804 878 1 002 1 139 1 269

EBITDA margin 6% 13% 13% 16% 15% 17% 26% 28% 33% 33% 33% 32% 33% 33% 33%

EBIT margin 1% 8% 8% 10% 8% 8% 19% 22% 27% 27% 27% 27% 28% 28% 28%

Net margin 0% 11% 15% 15% 13% 12% 19% 21% 24% 24% 23% 23% 24% 24% 24%


Cash flow statementChange in WC - 25 - 52 37 - 3 9 6 - 31 - 15 - 14 - 6 - 11 - 15 - 22 - 25 - 26

OCF - 6 33 151 169 190 233 459 586 770 801 850 927 1 054 1 198 1 337

Net capex - 46 - 134 - 571 - 683 - 695 - 522 - 209 - 174 - 180 - 187 - 198 - 213 - 237 - 262 - 286

Acquisitions/divestments 0 -2 923 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 45 -2 984 - 417 - 530 - 547 - 377 - 67 - 31 - 38 - 44 - 55 - 71 - 94 - 120 - 144

Equity raised/bought back 0 3 158 0 0 0 0 0 0 0 0 0 0 0 0 0

Change in debt 74 - 145 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 60 3 007 0 0 0 0 0 0 0 0 0 0 0 0 0

Net CF 9 56 - 267 - 362 - 357 - 145 392 554 732 757 794 856 960 1 078 1 194

2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.4 1.8 1.5 1.5 1.4 1.0 0.9 0.8 0.7 0.7 0.6 0.6 0.5 0.4

EV/EBITDA 18.5 13.5 9.8 9.7 8.1 3.7 3.1 2.3 2.3 2.1 2.0 1.7 1.5 1.4

P/E 49.3 27.5 24.0 27.1 25.7 11.9 9.7 7.4 7.3 6.9 6.3 5.5 4.8 4.4

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 10% 9% 9% 9% 9% 9% 9% 9% 9% 9% 10% 10% 10% 10% 10%


USD/MWh26 31 37 42 47 53 65 77 85 88 91 93 95 98 101

Fuel cost, USD/MWh 16 18 23 26 29 32 35 41 42 43 45 47 49 51 53

EBITDA/kW, USD 5 15 21 29 29 34 65 80 104 107 114 125 142 162 180

OGK-3


DCF

12m target price


Valuation


EBIT 110 150 120 138 468 603 834 856 916 1 013 1 176 1 357 1 527

Tax on EBIT - 26 - 36 - 29 - 33 - 112 - 145 - 200 - 205 - 220 - 243 - 282 - 326 - 367

After tax EBIT 84 114 91 105 356 458 634 650 696 770 894 1 031 1 161

Depreciation 67 94 125 157 169 176 183 191 198 207 216 226 237

Capex - 571 - 683 - 695 - 522 - 209 - 174 - 180 - 187 - 198 - 213 - 237 - 262 - 286

Change in WC 37 - 3 9 6 - 31 - 15 - 14 - 6 - 11 - 15 - 22 - 25 - 26

FCFF - 384 - 478 - 470 - 255 284 446 624 649 686 748 851 970 1 085

Discounted FCFF - 360 - 400 - 351 - 170 169 236 295 273 258 251 254 258 258

WACC 12.1%


NPV of cash flow 972


Fair EV 3 568

Net debt 2007 3 134

Minority interest 0

Fair MCap 6 702


Upside to FV 21%

12m TP, USD 0.161

Upside to TP 39%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 0.184 0.193 0.205 0.220 0.239

11.1% 0.165 0.172 0.180 0.191 0.204

12.1% 0.150 0.155 0.161 0.169 0.178

13.1% 0.138 0.142 0.146 0.152 0.159

14.1% 0.127 0.130 0.134 0.138 0.143

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 594 645 708 789 897

11.1% 492 529 575 632 705

12.1% 409 437 471 512 563

13.1% 341 362 388 418 456

14.1% 284 301 321 344 371

Terminal growth


Kostromskaya GRES 1 831 - 1 1 830 508 0 1 830 508

Gusinoozerskaya GRES 662 3 665 605 - 62 603 548

Pechorskaya GRES 497 6 504 475 0 504 475

Kharanorskaya GRES 374 1 376 873 - 28 347 808

Cherepetskaya GRES 236 10 246 172 - 129 117 82

Yuzhnouralskaya GRES 544 4 549 622 55 603 684

OGK-3 total 4 145 23 4 168 491 - 164 4 004 471

Plant


Existing assets New



OGK-4


Below-average fuel burn rate


Foreign strategic investor

6-month performance

Assets



2007e 2011e 2007e 2008e

-50%

-40%

-30%

-20%

-10%

0%

10%

20%


Plant Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Surgutskaya GRES-2 Khanty-Mansiysk 4 800 840 34 406 1 062

Smolenskaya GRES Smolensk 630 66 2 099 45

Shaturskaya GRES Moscow 1 100 344 4 912 446

Yayvinskaya GRES Perm 600 69 4 295 101

Berezovskaya GRES Krasnoyarsk 1 500 860 8 529 572

OGK-4 total 8 630 2 179 54 241 2 226

Plant Project

Completion

date

New

electric

capacity,

MW Fuel type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Surgutskaya GRES-2 new 2x400 MW CCGTs 2010 800 gas 859 725

Shaturskaya GRES new 400 MW CCGT 2009 400 gas 425 209

Yayvinskaya GRES new 400 MW CCGT 2010 400 gas 437 138

Berezovskaya GRES new 800 MW turbine 2009 800 coal 1 119 97

Gas82.78%

Coal16.48%

Fuel oil

0.05%

Peat0.69%

Gas71.78%

Coal27.80%

Fuel oil

0.18%

Peat0.23%

UES23%

E.On69%

Other minorities

8%

E.On76%

Other minorities

24%

OGK-4


Financials

Financial ratios

Operational data



Non-cash WC 48 57 71 93 144 153 159 186 207 216 237 251 262 274 286

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 852 2 796 2 916 3 068 3 810 4 586 5 300 6 284 7 552 8 869 10 329 11 869 13 459 15 097 16 790


Net debt (+) or cash (-) - 28 -1 448 - 359 583 197 - 599 -1 342 -2 271 -3 487 -4 764 -6 160 -7 641 -9 175 -10 758 -12 396



Electricity 896 1 075 1 406 1 965 3 091 3 371 3 496 4 079 4 546 4 758 5 222 5 524 5 771 6 022 6 302

Heat 21 28 36 41 45 50 58 68 70 73 75 78 81 85 89

Other 14 16 19 20 21 21 22 23 24 25 26 27 28 29 30

Cost of sales - 894 -1 068 -1 390 -1 669 -2 095 -2 318 -2 518 -2 866 -2 961 -3 112 -3 390 -3 588 -3 775 -3 967 -4 179

Fuel costs - 542 - 668 - 914 -1 086 -1 348 -1 507 -1 675 -1 978 -2 019 -2 118 -2 341 -2 481 -2 607 -2 734 -2 878

D&A - 52 - 62 - 100 - 151 - 188 - 208 - 214 - 224 - 234 - 245 - 257 - 269 - 282 - 295 - 309

Fixed costs - 300 - 338 - 377 - 432 - 559 - 603 - 629 - 665 - 708 - 749 - 792 - 838 - 887 - 938 - 993

EBITDA 93 117 175 513 1 255 1 337 1 277 1 533 1 919 1 996 2 197 2 316 2 395 2 472 2 559

EBIT 41 55 75 362 1 067 1 129 1 064 1 309 1 685 1 751 1 940 2 047 2 113 2 177 2 250

EBT 37 54 74 361 1 066 1 128 1 063 1 308 1 684 1 750 1 939 2 046 2 112 2 176 2 249

Net income 28 41 56 274 810 857 808 994 1 280 1 330 1 474 1 555 1 605 1 654 1 709

EBITDA margin 10% 10% 12% 25% 40% 39% 36% 37% 41% 41% 41% 41% 41% 40% 40%

EBIT margin 4% 5% 5% 18% 34% 33% 30% 31% 36% 36% 36% 36% 36% 35% 35%

Net margin 3% 4% 4% 14% 26% 25% 23% 24% 28% 27% 28% 28% 27% 27% 27%


Cash flow statementChange in WC - 36 - 5 - 12 - 26 - 53 - 13 - 9 - 27 - 21 - 10 - 21 - 14 - 11 - 12 - 13

OCF 27 99 145 400 947 1 054 1 013 1 192 1 494 1 566 1 710 1 811 1 876 1 938 2 006

Net capex - 38 - 502 -1 254 -1 346 - 568 - 252 - 250 - 254 - 265 - 276 - 299 - 316 - 327 - 339 - 352


ICF - 37 - 501 -1 252 -1 344 - 566 - 251 - 249 - 253 - 264 - 275 - 298 - 315 - 326 - 338 - 351


Change in debt 18 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 3 1 762 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2 - 2

2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 3.2 2.5 1.8 1.1 1.0 1.0 0.9 0.8 0.7 0.7 0.6 0.6 0.6 0.6

EV/EBITDA 30.6 20.5 7.0 2.9 2.7 2.8 2.3 1.9 1.8 1.6 1.6 1.5 1.5 1.4

P/E 122.1 89.3 18.4 6.2 5.9 6.2 5.1 3.9 3.8 3.4 3.2 3.1 3.0 3.0







Load factor (heat) 12% 12% 12% 12% 12% 12% 12% 12% 13% 13% 13% 13% 13% 13% 13%


USD/MWh18 21 26 35 47 53 58 68 75 77 79 82 85 88 91

Fuel cost, USD/MWh 11 13 17 19 20 24 28 33 33 34 35 37 38 40 42

EBITDA/kW, USD 11 14 20 57 114 121 116 139 174 181 199 210 217 224 232

OGK-4


DCF

12m target price


Valuation


EBIT 75 362 1 067 1 129 1 064 1 309 1 685 1 751 1 940 2 047 2 113 2 177 2 250

Tax on EBIT - 18 - 87 - 256 - 271 - 255 - 314 - 404 - 420 - 466 - 491 - 507 - 522 - 540

After tax EBIT 57 275 811 858 808 995 1 280 1 331 1 475 1 556 1 606 1 654 1 710

Depreciation 100 151 188 208 214 224 234 245 257 269 282 295 309

Capex -1 254 -1 346 - 568 - 252 - 250 - 254 - 265 - 276 - 299 - 316 - 327 - 339 - 352

Change in WC - 12 - 26 - 53 - 13 - 9 - 27 - 21 - 10 - 21 - 14 - 11 - 12 - 13

FCFF -1 109 - 945 379 801 763 938 1 229 1 290 1 411 1 496 1 549 1 599 1 654

WACC 11.8%




Fair EV 7 753

Net debt 2007e 1 448

Minority interest 0

Fair MCap 9 201

FV, USD 0.146

Upside to FV 83%

12m TP, USD 0.166

Upside to TP 108%

Dividend yield 0.2%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.198 0.210 0.224 0.244 0.270

10.8% 0.173 0.181 0.192 0.205 0.223

11.8% 0.152 0.158 0.166 0.176 0.188

12.8% 0.135 0.140 0.146 0.153 0.162

13.8% 0.121 0.125 0.129 0.134 0.141

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 1 229 1 314 1 421 1 559 1 745

10.8% 1 049 1 111 1 187 1 284 1 408

11.8% 902 948 1 004 1 073 1 160

12.8% 780 815 857 908 970

13.8% 678 705 737 775 821

Terminal growth


Surgutskaya GRES-2 5 179 19 5 198 1 083 810 6 008 1 252

Smolenskaya GRES 129 2 130 207 0 130 207

Shaturskaya GRES 387 21 408 371 233 641 583

Yayvinskaya GRES 436 4 440 733 154 594 990

Berezovskaya GRES 1 192 - 1 1 191 794 108 1 299 866

OGK-4 total 7 324 44 7 368 854 1 305 8 673 1 005

Plant


Existing assets New



OGK-5

Strengths Coal plant in European Russia


6-month performance

Assets



2007e 2011e 2007e 2008e

-50%

-40%

-30%

-20%

-10%

0%

10%

20%


Plant Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat

sales

2007,

k GCal

Konakovskaya GRES Tver 2 400 120 8 504 229

Nevinnomysskaya GRES Stavropol 1 290 729 6 236 1 781

Reftinskaya GRES Sverdlovsk 3 800 350 16 363 481

Sredneuralskaya GRES Sverdlovsk 1 182 1 193 7 276 4 278

OGK-5 total 8 672 2 392 38 379 6 769

Gas58%

Coal41%

Fuel oil1%

Gas57%

Coal42%

Fuel oil1%

Government26.4%

Enel52.9%

Gazprom and af f ilates

6.3%

Other minorities

14.4%

Government26.4%

Enel55.8%

Gazprom and af f ilates

6.4%EBRD5.2%

Other minorities

6.3%

Plant Project

Completion

date

New

electric

capacity,

MW

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Nevinnomysskaya GRES new 410 MW CCGT 2010 410 gas 442 134

Reftinskaya GRES

upgrade of six 300 MW units to

328MW and four 500MW units to

580MW

2013 488 coal 705 129

Sredneuralskaya GRES new 420 MW CCGT 2009 420 gas 448 147

OGK-5


Financials

Financial ratios

Operational data


Balance sheetsFixed assets 1 675 2 588 3 186 3 543 3 749 3 864 3 851 3 866 3 880 3 894 3 915 3 948 3 997 4 059 4 124

Non-cash WC 94 135 119 123 136 121 131 156 170 177 191 211 235 258 275

LT investments 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Equity 1 857 2 497 2 621 2 683 3 019 3 389 3 805 4 460 5 296 6 144 7 063 8 086 9 234 10 488 11 796


Net debt (+) or cash (-) - 295 - 118 332 645 534 270 - 142 - 758 -1 564 -2 393 -3 276 -4 246 -5 321 -6 491 -7 716



Electricity 845 1 039 1 438 1 767 2 302 2 533 2 729 3 240 3 553 3 689 4 010 4 443 4 964 5 468 5 840

Heat 56 64 70 104 136 169 204 238 241 252 262 270 279 288 300

Other 12 12 14 15 15 16 16 17 18 19 19 20 21 22 23

Cost of sales - 916 -1 060 -1 443 -1 672 -1 949 -2 160 -2 325 -2 638 -2 717 -2 848 -3 085 -3 392 -3 757 -4 130 -4 445

Fuel costs - 585 - 663 - 965 -1 135 -1 327 -1 493 -1 623 -1 897 -1 931 -2 020 -2 211 -2 470 -2 784 -3 102 -3 358

D&A - 74 - 81 - 129 - 151 - 163 - 168 - 176 - 185 - 193 - 202 - 211 - 221 - 231 - 243 - 256

Fixed costs - 257 - 316 - 349 - 386 - 460 - 499 - 525 - 556 - 592 - 627 - 663 - 701 - 742 - 785 - 831

EBITDA 78 148 221 379 682 741 817 1 059 1 307 1 332 1 436 1 583 1 759 1 913 1 996

EBIT 4 67 92 228 520 573 641 874 1 114 1 130 1 225 1 362 1 528 1 670 1 741

EBT - 2 79 88 224 516 570 637 870 1 110 1 127 1 221 1 358 1 524 1 666 1 737

Net income - 2 60 67 170 392 433 484 661 843 856 928 1 032 1 158 1 266 1 320

EBITDA margin 9% 13% 15% 20% 28% 27% 28% 30% 34% 34% 33% 33% 33% 33% 32%

EBIT margin 0% 6% 6% 12% 21% 21% 22% 25% 29% 29% 29% 29% 29% 29% 28%

Net margin 0% 5% 4% 9% 16% 16% 16% 19% 22% 22% 22% 22% 22% 22% 21%


Cash flow statementChange in WC - 8 - 13 19 - 9 - 15 12 - 13 - 25 - 14 - 7 - 15 - 20 - 24 - 23 - 17

OCF 47 137 218 317 544 617 652 826 1 026 1 055 1 128 1 237 1 370 1 490 1 562

Net capex - 117 - 332 - 662 - 645 - 441 - 357 - 237 - 201 - 208 - 216 - 232 - 254 - 281 - 305 - 321


ICF - 111 - 73 - 648 - 630 - 427 - 343 - 223 - 187 - 195 - 202 - 218 - 241 - 267 - 291 - 307


Change in debt 166 - 21 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 549 - 44 - 19 - 19 - 18 - 18 - 17 - 17 - 17 - 17 - 17 - 17 - 17 - 17 - 17

Net CF 485 20 - 448 - 332 99 256 411 622 814 836 892 979 1 085 1 181 1 237

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 4.0 2.9 2.3 1.8 1.6 1.5 1.3 1.2 1.1 1.0 0.9 0.8 0.8 0.7

EV/EBITDA 29.9 20.0 11.6 6.5 5.9 5.4 4.2 3.4 3.3 3.1 2.8 2.5 2.3 2.2

P/E 75.7 67.9 26.6 11.5 10.5 9.4 6.8 5.4 5.3 4.9 4.4 3.9 3.6 3.4

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 34% 32% 33% 33% 33% 34% 34% 34% 35% 35% 35% 36% 36% 36% 37%


USD/MWh22 28 35 43 52 58 67 79 85 88 90 92 94 96 100

Fuel cost, USD/MWh 15 18 24 27 30 34 40 46 46 48 50 51 53 55 57

EBITDA/kW, USD 9 17 25 43 70 75 82 106 131 133 144 158 176 191 200

OGK-5


DCF

12m target price


Valuation


EBIT 92 228 520 573 641 874 1 114 1 130 1 225 1 362 1 528 1 670 1 741

Tax on EBIT - 22 - 55 - 125 - 138 - 154 - 210 - 267 - 271 - 294 - 327 - 367 - 401 - 418

After tax EBIT 70 173 395 436 487 664 846 859 931 1 035 1 161 1 269 1 323

Depreciation 129 151 163 168 176 185 193 202 211 221 231 243 256

Capex - 662 - 645 - 441 - 357 - 237 - 201 - 208 - 216 - 232 - 254 - 281 - 305 - 321

Change in WC 19 - 9 - 15 12 - 13 - 25 - 14 - 7 - 15 - 20 - 24 - 23 - 17

FCFF - 445 - 329 102 259 414 624 817 839 895 982 1 088 1 184 1 240

Discounted FCFF - 420 - 280 78 178 257 349 411 379 364 360 359 352 332

WACC 11.1%




Fair EV 6 444

Net debt 2007 118

Minority interest 0

Fair MCap 6 562


Upside to FV 45%

12m TP, USD 0.209

Upside to TP 64%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.1% 0.254 0.274 0.299 0.333 0.380

10.1% 0.216 0.231 0.248 0.271 0.302

11.1% 0.186 0.197 0.209 0.225 0.246

12.1% 0.161 0.169 0.179 0.190 0.205

13.1% 0.141 0.147 0.154 0.163 0.173

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.1% 1 005 1 085 1 186 1 321 1 510

10.1% 853 911 982 1 073 1 195

11.1% 732 774 825 890 972

12.1% 632 664 702 749 807

13.1% 550 575 603 638 679

Terminal growth


Konakovskaya GRES 1 246 7 1 253 522 0 1 253 522

Nevinnomysskaya GRES 767 43 809 627 149 958 743

Reftinskaya GRES 3 529 0 3 529 929 143 3 672 966

Sredneuralskaya GRES 1 013 104 1 117 945 163 1 280 1 084

OGK-5 total 6 555 153 6 707 774 455 7 162 826

Plant


Existing assets New



OGK-6




Above-average effective fuel price


6-month performance

Assets



2007e 2011e 2007e 2008e

-45%

-35%

-25%

-15%

-5%

5%

15%


Plant Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat

sales

2007,

k GCal

GRES-24 Ryazan 310 0 1 824 0

Ryazanskaya GRES Ryazan 2 650 1 234 8 128 2 632

Krasnoyarskaya GRES-2 Krasnoyarsk 1 250 1 176 4 682 1 275

Novocherkasskaya GRES Rostov 2 112 75 9 380 116

Kirishskaya GRES Leningrad 2 100 180 6 645 234

Cherepovetskaya GRES Vologda 630 39 3 648 108

OGK-6 total 9 052 2 704 34 308 4 366

Plant Project

Completion

date

New

electric

capacity,

MW

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

GRES-24 upgrade of 310 MW unit with 110 MW turbine 2009 110 gas 120 - 22

Novocherkasskaya GRES new 330 MW turbine 2011 330 coal 476 - 86

Kirishskaya GRES upgrade of 300 MW 6th unit with 500 MW CCGT 2010 500 gas 543 - 27

Cherepovetskaya GRES new 330 MW 4th unit 2011 330 coal 476 - 188

Gas50%

Coal47%Fuel

oil3%

Gas39%

Coal60%Fuel

oil1%

UES93%

Other minorities

7%

Gazprom60%

Other minorities

40%

OGK-6


Financials

Financial ratios

Operational data


Balance sheetFixed assets 1 096 1 283 1 753 2 204 2 689 3 353 3 287 3 277 3 267 3 257 3 251 3 255 3 271 3 296 3 337

Non-cash WC 48 57 68 75 81 95 115 132 148 155 167 184 203 223 251

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 724 1 595 1 560 1 440 1 396 1 479 1 725 2 118 2 675 3 253 3 877 4 582 5 379 6 261 7 268


Net debt (+) or cash (-) 242 - 446 67 653 1 190 1 789 1 501 1 115 564 - 17 - 635 -1 319 -2 082 -2 919 -3 857



Electricity 944 1 111 1 389 1 573 1 656 1 946 2 382 2 732 3 080 3 228 3 491 3 860 4 282 4 733 5 343

Heat 67 86 85 110 132 155 181 208 214 224 231 235 239 244 247

Other 14 16 19 20 21 21 22 23 24 25 26 27 28 29 31

Cost of sales -1 039 -1 211 -1 568 -1 762 -1 813 -1 960 -2 207 -2 426 -2 563 -2 695 -2 905 -3 172 -3 477 -3 821 -4 271

Fuel costs - 610 - 740 -1 036 -1 168 -1 154 -1 213 -1 386 -1 563 -1 649 -1 733 -1 890 -2 103 -2 349 -2 631 -3 015

D&A - 90 - 92 - 111 - 132 - 151 - 174 - 192 - 200 - 208 - 216 - 224 - 233 - 243 - 254 - 266

Fixed costs - 338 - 379 - 421 - 462 - 508 - 573 - 628 - 663 - 706 - 747 - 790 - 836 - 885 - 936 - 990

EBITDA 82 100 42 79 153 344 578 744 971 1 006 1 076 1 192 1 325 1 448 1 625

EBIT - 8 7 - 69 - 53 2 169 386 544 763 790 851 959 1 082 1 194 1 359

EBT - 33 - 16 - 93 - 77 - 21 146 363 521 740 768 829 936 1 059 1 172 1 337

Net income - 27 - 16 - 93 - 77 - 21 111 276 396 563 583 630 711 805 891 1 016

EBITDA margin 8% 8% 3% 5% 8% 16% 22% 25% 29% 29% 29% 29% 29% 29% 29%

EBIT margin neg 1% neg neg 0% 8% 15% 18% 23% 23% 23% 23% 24% 24% 24%

Net margin neg neg neg neg neg 5% 11% 13% 17% 17% 17% 17% 18% 18% 18%


Cash flow statementChange in WC 8 - 5 - 10 - 10 - 7 - 16 - 23 - 17 - 16 - 7 - 12 - 17 - 19 - 21 - 28

OCF 69 98 54 87 151 293 468 602 777 814 865 950 1 052 1 147 1 277

Net capex - 61 - 195 - 547 - 664 - 684 - 897 - 189 - 190 - 198 - 205 - 218 - 238 - 259 - 280 - 307


ICF - 61 - 195 - 547 - 664 - 684 - 897 - 189 - 190 - 198 - 205 - 218 - 238 - 259 - 280 - 307


Change in debt 40 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 13 774 - 24 - 24 - 23 - 23 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22

Net CF - 5 677 - 517 - 600 - 556 - 627 257 389 557 587 624 690 770 845 947

2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.7 1.4 1.2 1.1 1.0 0.8 0.7 0.6 0.6 0.6 0.5 0.5 0.4 0.4

EV/EBITDA 20.8 49.8 26.3 13.5 6.0 3.6 2.8 2.1 2.1 1.9 1.7 1.6 1.4 1.3

P/E neg neg neg neg 22.6 9.1 6.4 4.5 4.3 4.0 3.5 3.1 2.8 2.5

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 19% 18% 19% 19% 19% 19% 19% 20% 20% 20% 20% 20% 21% 21% 21%


USD/MWh32 35 40 43 49 57 67 79 88 91 94 96 99 102 105

Fuel cost, USD/MWh 20 24 30 32 34 35 39 45 47 49 51 52 54 57 59

EBITDA/kW, USD 9 11 5 9 17 36 56 72 94 97 104 115 128 140 157

OGK-6


DCF

12m target price


Valuation


EBIT - 69 - 53 2 169 386 544 763 790 851 959 1 082 1 194 1 359

Tax on EBIT 17 13 0 - 41 - 93 - 130 - 183 - 190 - 204 - 230 - 260 - 287 - 326

After tax EBIT - 53 - 40 2 129 293 413 580 600 647 728 822 908 1 033

Depreciation 111 132 151 174 192 200 208 216 224 233 243 254 266

Capex - 547 - 664 - 684 - 897 - 189 - 190 - 198 - 205 - 218 - 238 - 259 - 280 - 307

Change in WC - 10 - 10 - 7 - 16 - 23 - 17 - 16 - 7 - 12 - 17 - 19 - 21 - 28

FCFF - 499 - 582 - 538 - 610 274 406 574 604 641 707 787 862 964

Discounted FCFF - 468 - 486 - 399 - 402 160 211 266 248 234 230 228 221 220

WACC 12.5%




Fair EV 2 409

Net debt 2007e 446

Minority interest 0

Fair MCap 2 855


Upside to FV 13%

12m TP, USD 0.102

Upside to TP 30%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 0.129 0.140 0.153 0.170 0.193

11.5% 0.106 0.115 0.124 0.137 0.152

12.5% 0.088 0.094 0.102 0.111 0.122

13.5% 0.073 0.078 0.083 0.090 0.098

14.5% 0.061 0.064 0.069 0.074 0.080

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 395 433 480 539 618

11.5% 316 344 379 421 475

12.5% 252 274 299 330 369

13.5% 200 217 236 259 287

14.5% 157 170 184 202 223

Terminal growth


GRES-24 173 0 173 557 - 24 148 479

Ryazanskaya GRES 397 10 407 154 0 407 154

Krasnoyarskaya GRES-2 756 12 769 615 0 769 615

Novocherkasskaya GRES 1 040 3 1 043 494 - 97 947 448

Kirishskaya GRES 203 177 379 181 - 30 349 166

Cherepovetskaya GRES 301 4 305 484 - 212 93 148

OGK-6 total 2 870 206 3 076 340 - 363 2 713 300

Plant


Existing assets New



TGK-1

Strengths Hydroelectric power plants


Weaknesses Above-average effective fuel price


6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

TGK-1 RTS Index RTS Electric Utilities Index

Branch Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Nevsky Thermal St. Peterburg/Leningrad 2 806 12 219 11 427 20 318

Nevsky Hydro St. Peterburg/Leningrad 631 n/a 3 404 n/a

Karelsky Thermal Karelia 282 689 988 1 657

Karelsky Hydro Karelia 634 n/a 3 068 n/a

Kolsky Hydro Murmansk 1 593 n/a 6 734 n/a

Apatitsk CHP Murmansk 323 735 442 1 251

Murmansk CHP Murmansk 12 1 111 37 2 172

TGK-1 total 6 280 14 754 26 101 25 397

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Nevsky Thermal expansion and reconstruction 2013 3677 3480 gas 4 060 - 98

Nevsky Hydro expansion and reconstruction 2012 355 n/a n/a 327 174

Karelsky Thermal expansion and reconstruction 2012 182 160 gas 204 - 22

Karelsky Hydro expansion and reconstruction 2015 11 n/a n/a 10 3

Kolsky Hydro expansion and reconstruction 2014 117 n/a n/a 91 59

Murmansk CHP replacement of old capacity with 3x180 MW turbines 2013 540 780 coal 608 18

Gas89%

Coal4%

Fuel oil7%

Gas90%

Coal6%

Fuel oil4%

UES56%

Fortum26%

Norilsk Nickel

7%

Other minorities

11%

Gazprom and af f iliated

46%

Fortum26%

Norilsk Nickel

6%

Other minorities

22%

TGK-1


Financials

Financial ratios

Operational data



Non-cash WC 80 95 102 134 170 174 208 242 254 264 274 285 297 309 322

LT investments 49 16 17 16 16 16 15 15 15 15 15 15 15 15 15

Equity 934 2 251 2 295 2 508 3 169 4 072 4 766 5 627 6 569 7 566 8 622 9 742 10 931 12 194 13 539


Net debt (+) or cash (-) 217 - 827 113 1 946 2 521 2 378 2 133 1 157 84 -1 061 -2 269 -3 542 -4 886 -6 307 -7 810


Income statementRevenues 750 989 1 260 1 994 3 016 3 952 4 704 5 479 5 754 5 971 6 209 6 459 6 719 6 992 7 277

Electricity 368 453 598 1 167 2 029 2 787 3 318 3 899 4 139 4 284 4 451 4 627 4 810 5 002 5 202

Heat 353 503 625 787 946 1 122 1 342 1 534 1 566 1 636 1 705 1 777 1 852 1 931 2 013

Other 29 33 38 40 42 43 44 46 49 51 53 55 57 59 62

Cost of sales - 755 -1 010 -1 254 -1 571 -2 057 -2 657 -3 289 -3 802 -3 863 -4 018 -4 192 -4 376 -4 569 -4 771 -4 983

Fuel costs - 330 - 498 - 655 - 831 -1 133 -1 549 -2 060 -2 498 -2 488 -2 577 -2 682 -2 792 -2 908 -3 028 -3 154

D&A - 50 - 71 - 108 - 178 - 266 - 349 - 385 - 409 - 419 - 430 - 441 - 453 - 464 - 476 - 489

Fixed costs - 375 - 440 - 490 - 562 - 658 - 758 - 845 - 896 - 955 -1 011 -1 069 -1 131 -1 197 -1 266 -1 340

EBITDA 51 57 122 610 1 234 1 653 1 809 2 095 2 321 2 394 2 469 2 546 2 627 2 710 2 796

EBIT 1 - 13 14 432 968 1 304 1 424 1 686 1 901 1 964 2 027 2 094 2 162 2 233 2 307

EBT - 13 - 36 - 9 409 945 1 281 1 402 1 665 1 879 1 942 2 006 2 072 2 141 2 212 2 285

Net income - 13 - 36 - 9 310 717 972 777 869 950 1 006 1 065 1 130 1 199 1 275 1 356

EBITDA margin 7% 6% 10% 31% 41% 42% 38% 38% 40% 40% 40% 39% 39% 39% 38%

EBIT margin 0% neg 1% 22% 32% 33% 30% 31% 33% 33% 33% 32% 32% 32% 32%



Cash flow statement

Change in WC 31 - 8 - 5 - 37 - 38 - 8 - 37 - 35 - 12 - 10 - 11 - 11 - 12 - 12 - 13

OCF 60 59 120 475 969 1 337 1 148 1 266 1 381 1 450 1 519 1 595 1 676 1 763 1 856

Net capex - 126 - 279 -1 044 -2 327 -1 565 -1 220 - 924 - 258 - 276 - 273 - 278 - 287 - 297 - 307 - 317


ICF - 109 - 244 -1 044 -2 327 -1 565 -1 220 - 924 - 258 - 276 - 273 - 278 - 287 - 297 - 307 - 317


Change in debt 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 60 1 206 - 24 - 23 - 23 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22

Net CF 11 1 021 - 948 -1 875 - 619 95 202 986 1 083 1 155 1 220 1 286 1 357 1 434 1 517

2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 4.4 3.4 2.2 1.4 1.1 0.9 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.6

EV/EBITDA 75.2 35.3 7.1 3.5 2.6 2.4 2.1 1.9 1.8 1.8 1.7 1.6 1.6 1.5

P/E neg neg 16.6 7.2 5.3 6.6 5.9 5.4 5.1 4.8 4.6 4.3 4.0 3.8

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 21% 20% 20% 20% 21% 21% 22% 22% 22% 22% 22% 23% 23% 23% 23%

Effective electricity price,

USD/MWh17 19 25 41 57 67 71 81 86 89 92 95 98 101 105

Fuel cost, USD/MWh 15 21 27 29 32 37 44 52 51 53 55 57 59 61 64

EBITDA/kW, USD 8 9 19 89 155 185 185 213 236 243 251 258 267 275 284

TGK-1


DCF

12m target price


Valuation


EBIT 16 220 424 639 770 944 1 127 1 162 1 199 1 237 1 277 1 318 1 360

Tax on EBIT - 4 - 53 - 102 - 153 - 430 - 566 - 685 - 686 - 685 - 682 - 676 - 667 - 655

After tax EBIT 12 167 323 486 340 378 442 476 514 555 601 651 706

Depreciation 92 111 128 146 148 153 158 163 168 173 178 184 190

Capex - 129 - 127 - 117 - 118 - 119 - 118 - 121 - 125 - 130 - 135 - 140 - 145 - 150

Change in WC - 3 - 7 4 3 - 14 - 13 - 10 - 5 - 6 - 6 - 6 - 7 - 7

FCFF - 28 144 337 517 355 401 468 508 546 588 633 683 738

Discounted FCFF - 27 120 250 341 208 209 217 209 200 191 183 176 169

WACC 12.5%




Fair EV 4 231

Net debt 2007e 827

LT investments 22

Minority interest - 8

Fair MCap 5 073


Upside to FV -1%

12m TP, USD 0.00151

Upside to TP 13%

Dividend yield 0.0%



Shares outstanding, mn 3 850 960

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 0.00191 0.00205 0.00223 0.00246 0.00276

11.5% 0.00159 0.00170 0.00183 0.00199 0.00220

12.5% 0.00133 0.00142 0.00151 0.00163 0.00178

13.5% 0.00112 0.00118 0.00126 0.00135 0.00145

14.5% 0.00094 0.00099 0.00105 0.00112 0.00120

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 993 1 081 1 188 1 325 1 504

11.5% 804 869 948 1 045 1 168

12.5% 650 699 758 829 916

13.5% 523 560 605 658 722

14.5% 416 445 480 520 567

Terminal growth


Nevsky Thermal 223 1 250 1 473 525 - 110 1 363 486

Nevsky Hydro 414 n/a 414 656 196 610 967

Karelsky Thermal 83 90 173 613 - 25 148 525

Karelsky Hydro 666 n/a 666 1 051 3 669 1 055

Kolsky Hydro 1 604 n/a 1 604 1 007 66 1 670 1 048

Apatitsk CHP 40 93 133 413 0 133 413

Murmansk CHP - 1 138 137 11 455 20 158 13 154

TGK-1 total 3 029 1 572 4 601 733 150 4 751 757

Branch


Existing assets New



TGK-2





6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%


Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Vologda Vologda 40 602 128 980

Kostroma Kostroma 224 1 763 1 165 2 004

Novgorod Novgorod 190 630 802 1 064

Tver Tver 279 2 187 1 485 3 872

Yaroslavl Yaroslavl 801 4 147 2 761 5 757

Arkhangelsk Arkhangelsk 1 049 3 142 3 832 5 189

TGK-2 total 2 583 12 471 10 174 18 865

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Vologda new 95 MW CCGT 2010 95 90 gas 104 29

Kostroma expansion with 160 MW CCGT 2009 160 0 gas 174 14

Novgorod gas expansion with 160 MW CCGT 2010 160 90 gas 173 48

Novgorod coal expansion with 120 MW turbine 2010 120 52 coal 170 - 25

Tver gas expansion with 160 MW CCGT 2009 160 0 gas 172 13

Tver coal expansion with 115 MW turbine 2010 115 175 coal 162 - 34

Yaroslavl expansion with 160 MW CCGT 2010 160 0 gas 172 20

Gas62%

Coal13%

Fuel oil24%

Peat1%

Gas52%

Coal33%

Fuel oil4%

Peat11%

UES49%

Prosperity capital24%

Industrial investments

5%Municipal property

2%State1%

Other minorities

19%

RWE-Sintez consortium

43% Prosperity capital18%

Industrial investments

4%Municipal property

1%State1%

Other minorities

33%

TGK-2


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 400 474 989 1 487 1 591 1 559 1 528 1 526 1 523 1 519 1 515 1 510 1 505 1 500 1 494

Non-cash WC 49 92 87 83 85 65 70 78 81 85 89 93 97 102 107

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 304 390 785 896 1 139 1 355 1 565 1 827 2 113 2 404 2 702 3 006 3 317 3 634 3 957


Net debt (+) or cash (-) 115 144 257 642 507 239 3 - 252 - 538 - 830 -1 128 -1 433 -1 744 -2 062 -2 386


Income statement*

Revenues 346 745 858 1 037 1 351 1 451 1 564 1 751 1 827 1 904 1 992 2 085 2 183 2 286 2 394

Electricity 128 360 394 547 824 878 918 1 024 1 076 1 114 1 164 1 217 1 272 1 331 1 392

Heat 195 358 434 457 493 538 611 691 713 750 786 825 865 908 953

Other 23 27 30 32 33 34 35 37 39 40 42 44 45 47 49

Cost of sales - 345 - 656 - 822 - 839 - 999 -1 128 -1 245 -1 399 -1 442 -1 512 -1 592 -1 677 -1 767 -1 861 -1 961

Fuel costs - 191 - 469 - 598 - 572 - 670 - 763 - 866 -1 000 -1 019 -1 067 -1 123 -1 183 -1 246 -1 312 -1 382

D&A - 17 - 21 - 35 - 57 - 77 - 89 - 91 - 95 - 99 - 103 - 107 - 111 - 115 - 120 - 124

Fixed costs - 137 - 166 - 189 - 209 - 252 - 276 - 288 - 304 - 324 - 343 - 363 - 384 - 406 - 429 - 454

EBITDA 21 114 76 260 434 417 416 453 490 501 513 526 539 552 565

EBIT 4 92 41 203 357 328 324 358 391 398 407 415 424 432 440

EBT - 6 81 29 191 345 317 313 347 380 387 396 404 413 421 429

Net income - 6 62 22 145 263 241 238 264 289 294 301 307 314 320 326

EBITDA margin 6% 15% 9% 25% 32% 29% 27% 26% 27% 26% 26% 25% 25% 24% 24%

EBIT margin 1% 12% 5% 20% 26% 23% 21% 20% 21% 21% 20% 20% 19% 19% 18%

Net margin neg 8% 3% 14% 19% 17% 15% 15% 16% 15% 15% 15% 14% 14% 14%

Cash flow statement

Change in WC - 39 - 38 7 0 - 3 19 - 6 - 8 - 3 - 3 - 4 - 4 - 4 - 5 - 5

OCF - 25 56 76 215 347 360 334 361 395 404 414 425 435 446 457

Net capex - 31 - 65 - 532 - 606 - 212 - 88 - 90 - 93 - 96 - 99 - 102 - 106 - 110 - 114 - 118


ICF - 38 - 64 - 532 - 605 - 211 - 87 - 89 - 92 - 95 - 98 - 102 - 106 - 110 - 114 - 118


Change in debt 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 61 - 12 347 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12

Net CF - 2 - 20 - 109 - 403 124 261 233 258 289 294 301 308 314 321 327


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.7 1.5 1.2 0.9 0.9 0.8 0.7 0.7 0.7 0.6 0.6 0.6 0.5 0.5

EV/EBITDA 11.0 16.5 4.8 2.9 3.0 3.0 2.8 2.5 2.5 2.4 2.4 2.3 2.3 2.2

P/E 23.7 65.5 10.1 5.6 6.1 6.1 5.5 5.1 5.0 4.9 4.8 4.7 4.6 4.5

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 18% 17% 17% 18% 18% 19% 19% 19% 19% 19% 19% 20% 20% 20% 20%


USD/MWh15 41 46 56 65 70 75 84 88 91 93 96 100 103 106

Fuel cost, USD/MWh 23 54 69 59 53 61 71 82 83 87 90 94 97 101 105

EBITDA/kW, USD 9 44 30 98 135 130 130 141 153 156 160 164 168 172 176

TGK-2


DCF

12m target price, common


Valuation


EBIT 41 203 357 328 324 358 391 398 407 415 424 432 440

Tax on EBIT - 10 - 49 - 86 - 79 - 78 - 86 - 94 - 96 - 98 - 100 - 102 - 104 - 106

After tax EBIT 31 154 271 249 247 272 297 302 309 316 322 328 335

Depreciation 35 57 77 89 91 95 99 103 107 111 115 120 124

Capex - 532 - 606 - 212 - 88 - 90 - 93 - 96 - 99 - 102 - 106 - 110 - 114 - 118

Change in WC 7 0 - 3 19 - 6 - 8 - 3 - 3 - 4 - 4 - 4 - 5 - 5

FCFF - 459 - 394 133 269 242 266 297 303 309 316 323 329 336

Discounted FCFF - 433 - 334 101 184 148 146 146 134 123 112 103 94 86

WACC 11.4%



NPV of terminal value 933

Fair EV 1 544

Net debt 2007e (adj. for SPO in 2008) 212

Minority interest 0

Fair MCap 1 755

Common Preferred

FV, USD 0.00120 0.000734

Upside to FV 20% 1%

12m TP, USD 0.00136 0.000832

Upside to TP 36% 15%

Dividend yield 0.01% 0.01%

Expected total return over 12m 36% 15%

Current price, USD 0.00100 0.000725

Shares outstanding, mn 1 455 996 16 501


WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.4% 0.00166 0.00178 0.00192 0.00211 0.00238

10.4% 0.00142 0.00150 0.00161 0.00174 0.00191

11.4% 0.00122 0.00128 0.00136 0.00145 0.00157

12.4% 0.00106 0.00110 0.00116 0.00123 0.00131

13.4% 0.00092 0.00096 0.00100 0.00105 0.00111

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.4% 835 899 981 1 088 1 234

10.4% 700 746 804 878 974

11.4% 589 624 666 718 784

12.4% 498 524 556 594 641

13.4% 421 442 465 494 528

Terminal growth


Vologda 8 21 30 743 32 62 1 554

Kostroma 64 77 141 629 16 157 699

Novgorod 59 39 98 518 21 119 626

Tver 150 273 423 1 516 - 26 397 1 424

Yaroslavl 192 306 498 622 22 520 649

Arkhangelsk 217 242 459 438 0 459 438

TGK-2 total 690 959 1 649 639 65 1 714 664

Branch


Existing assets New



Mosenergo (TGK-3)



Favourable heat business regulation

Weaknesses Gazprom's corporate governance

6-month performance

Assets



2007e 2011e 2007e 2008e

-40%

-30%

-20%

-10%

0%

10%

20%

Mosenergo RTS Index RTS Electric Utilities Index

Plant Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

GES-1 Moscow city 95 951 377 1 759

GRES-3 Moscow region 658 341 180 397

CHP-6 Moscow region 24 139 32 175

CHP-8 Moscow city 605 2 192 2 908 2 179

CHP-9 Moscow city 220 859 1 335 1 313

CHP-11 Moscow city 330 1 011 2 139 2 475

CHP-12 Moscow city 408 2 043 2 824 3 296

CHP-16 Moscow city 360 1 484 2 371 3 660

CHP-17 Moscow region 192 712 805 568

CHP-20 Moscow city 730 2 400 4 423 4 671

CHP-21 Moscow city 1 350 4 618 9 169 10 208

CHP-22 Moscow region 1 320 3 614 8 635 9 039

CHP-23 Moscow city 1 410 4 515 8 962 8 567

CHP-25 Moscow city 1 370 4 088 9 186 6 360

CHP-26 Moscow city 1 410 4 006 8 725 8 450

CHP-27 Moscow region 610 1 276 1 503 2 253

CHP-28 Moscow city 25 40 97 187

Mosenergo total 11 117 34 289 63 673 65 557

Plant Project

Completion

date

New electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial investment

outlay,

USD mn

NPV,

USD mn

CHP-9 new 61.5 MW CCGT 2009 61.5 0 gas 61

CHP-12 new 540 MW CCGT 2010 540 0 gas 533






CHP-27 2 new 450 MW CCGTs 2011 900 0 gas 888

- 79

Gas98.2%

Coal1.4%

Fuel oil

0.4%

Fuel mix, 2007e

Gas98.5%

Coal1.2%

Fuel oil

0.3%

Fuel mix, 2011e

UES36%

Gazprom50%City of

Moscow5%

Other minorities

9%

Ownership structure, 2007e

Gazprom53%

City of Moscow

27%

Other minorities

20%


Mosenergo (TGK-3)


Financials

Financial ratios

Operational data



Non-cash WC 17 477 87 147 215 298 365 426 448 465 488 512 537 564 592

LT investments 13 51 52 50 49 48 47 47 47 47 47 47 47 47 47

Equity 1 485 5 525 5 959 6 386 7 052 7 656 8 516 9 716 11 224 12 783 14 414 16 120 17 907 19 776 21 734


Net debt (+) or cash (-) 581 - 195 - 378 - 422 - 270 161 - 583 -1 847 -3 461 -5 134 -6 872 -8 683 -10 570 -12 538 -14 591



Electricity 1 126 1 418 2 024 2 795 3 227 3 754 4 723 5 519 5 943 6 149 6 483 6 839 7 214 7 611 8 030

Heat 1 165 1 320 1 814 2 216 2 565 2 929 3 475 4 043 4 101 4 285 4 460 4 644 4 835 5 035 5 243

Other 171 208 237 252 260 269 278 291 304 317 329 343 357 371 386

Cost of sales -2 256 -2 762 -3 516 -4 205 -4 831 -5 799 -6 966 -8 076 -8 155 -8 484 -8 904 -9 349 -9 817 -10 309 -10 827

Fuel costs -1 225 -1 442 -2 052 -2 596 -3 072 -3 855 -4 864 -5 862 -5 814 -6 021 -6 313 -6 623 -6 948 -7 289 -7 647

D&A - 140 - 266 - 309 - 348 - 388 - 446 - 481 - 502 - 518 - 533 - 550 - 567 - 585 - 604 - 623

Fixed costs - 890 -1 055 -1 155 -1 261 -1 371 -1 497 -1 621 -1 712 -1 823 -1 929 -2 041 -2 159 -2 284 -2 417 -2 557

EBITDA 217 341 745 1 275 1 473 1 460 1 847 2 128 2 552 2 636 2 748 2 865 2 989 3 119 3 255

EBIT 77 75 436 927 1 084 1 013 1 366 1 626 2 034 2 102 2 198 2 298 2 404 2 515 2 632

EBT 64 118 402 893 1 052 981 1 334 1 594 2 003 2 071 2 167 2 267 2 373 2 484 2 600

Net income 48 90 305 679 799 746 1 014 1 212 1 522 1 574 1 647 1 723 1 803 1 888 1 976

EBITDA margin 9% 12% 18% 24% 24% 21% 22% 22% 25% 25% 24% 24% 24% 24% 24%

EBIT margin 3% 3% 11% 18% 18% 15% 16% 16% 20% 20% 19% 19% 19% 19% 19%

Net margin 2% 3% 7% 13% 13% 11% 12% 12% 15% 15% 15% 15% 15% 15% 14%


Cash flow statementChange in WC 18 - 161 397 - 65 - 71 - 88 - 74 - 61 - 22 - 18 - 23 - 24 - 26 - 27 - 28

OCF 253 122 1 045 995 1 149 1 136 1 453 1 684 2 050 2 121 2 205 2 297 2 394 2 496 2 603

Net capex - 487 -1 388 - 835 - 901 -1 261 -1 534 - 673 - 377 - 389 - 401 - 419 - 438 - 457 - 478 - 499

Acquisitions/divestments - 22 - 902 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 508 -2 262 - 804 - 870 -1 231 -1 505 - 644 - 348 - 360 - 372 - 390 - 409 - 428 - 449 - 470


Change in debt 417 - 133 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 391 2 198 - 65 - 65 - 63 - 62 - 60 - 60 - 60 - 60 - 60 - 60 - 60 - 60 - 60

Net CF 135 58 176 61 - 145 - 430 748 1 276 1 629 1 688 1 754 1 828 1 905 1 987 2 072

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.3 1.7 1.3 1.1 1.0 0.8 0.7 0.7 0.6 0.6 0.6 0.6 0.5 0.5

EV/EBITDA 20.1 9.2 5.4 4.6 4.7 3.7 3.2 2.7 2.6 2.5 2.4 2.3 2.2 2.1

P/E 78.6 23.0 10.4 8.8 9.4 6.9 5.8 4.6 4.5 4.3 4.1 3.9 3.7 3.6

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 23% 22% 24% 24% 24% 25% 25% 25% 25% 26% 26% 26% 26% 27% 27%


USD/MWh19 24 32 43 51 57 67 79 84 87 90 93 96 99 102

Fuel cost, USD/MWh 21 25 33 40 49 58 69 84 83 85 87 90 92 94 97

EBITDA/kW, USD 20 31 64 106 117 108 125 144 173 179 186 194 203 211 221

Mosenergo (TGK-3)


DCF

12m target price


Valuation


EBIT 436 927 1 084 1 013 1 366 1 626 2 034 2 102 2 198 2 298 2 404 2 515 2 632

Tax on EBIT - 105 - 222 - 260 - 243 - 328 - 390 - 488 - 505 - 528 - 552 - 577 - 604 - 632

After tax EBIT 331 705 824 770 1 038 1 235 1 546 1 598 1 670 1 747 1 827 1 911 2 000

Depreciation 309 348 388 446 481 502 518 533 550 567 585 604 623

Capex - 835 - 901 -1 261 -1 534 - 673 - 377 - 389 - 401 - 419 - 438 - 457 - 478 - 499

Change in WC 397 - 65 - 71 - 88 - 74 - 61 - 22 - 18 - 23 - 24 - 26 - 27 - 28

FCFF 202 86 - 120 - 406 772 1 300 1 653 1 712 1 778 1 852 1 929 2 011 2 096

Discounted FCFF 189 72 - 88 - 264 446 665 750 688 633 585 540 499 460

WACC 12.8%




Fair EV 9 515

Net debt 2007 195

Minority interest 0

Fair MCap 9 710


Upside to FV 38%

12m TP, USD 0.278

Upside to TP 57%

Dividend yield 2.3%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 0.331 0.349 0.370 0.397 0.431

11.8% 0.290 0.303 0.319 0.338 0.363

12.8% 0.257 0.266 0.278 0.292 0.310

13.8% 0.228 0.236 0.245 0.256 0.268

14.8% 0.204 0.210 0.217 0.225 0.235

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 1 151 1 212 1 286 1 380 1 501

11.8% 1 008 1 053 1 108 1 176 1 260

12.8% 890 925 966 1 015 1 076

13.8% 791 818 849 886 931

14.8% 707 728 753 781 814

Terminal growth


All plants 5 185 5 646 10 831 973 - 89 10 742 965

Mosenergo 5 185 5 646 10 831 973 - 89 10 742 965

Plant


Existing assets New



TGK-4




6-month performance, common

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

TGK-4 common RTS Index

RTS Electric Utilities Index

Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Belgorod Belgorod 142 2 552 664 3 452

Bryansk Bryansk 50 236 158 290

Voronezh Voronezh 180 2 274 894 3 930

Kaluga Kaluga 12 70 24 30

Kursk Kursk 197 2 336 873 2 600

Lipetsk Lipetsk 543 3 103 1 871 4 307

Orel Orel 342 1 129 1 362 1 620

Ryazan Ryazan 100 416 492 575

Smolensk Smolensk 403 1 497 1 851 2 140

Tambov Tambov 315 1 139 1 123 1 413

Tula Tula 1 028 2 984 3 423 5 640

TGK-4 total 3 312 17 735 12 737 25 997

Branch Project*

Completion

date

New electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial investment

outlay,

USD mn

NPV,

USD mn

Belgorod 69 MW CCGT and 70 MW CCGT 2010 136 0 gas 216 - 57

Bryansk 90 MW CCGT 2010 90 0 gas 97 - 4

Voronezh 2x45 MW and 25 MW CCGTs 2009 115 0 gas 122 30

Kaluga 34.5 MW CCGT 2008 34.5 0 gas 36 - 1

Kursk 31.5 MW CCGT and 2 new 45+25 MW turbines 2009 146.5 0 gas 156 23

Lipetsk 52 and 320 MW CCGTs 2010 372 0 gas 458 - 36

Orel 31.5 MW CCGT 2009 31.5 0 gas 33 8

Ryazan 160 MW CCGT 2010 160 0 gas 174 2

Tula 225 MW turbine 2010 225 0 gas 244 - 26

* All projects imply reconstruction/expansion of existing capacity

Gas98%

Coal1%

Fuel oil1%

Gas98%

Coal1%

Fuel oil1%

UES47%

Archivo Ltd.14%

Immenso Enterprises

Ltd.

7%

Other minorities

32%

Onexim Holdings

Ltd.

52%

Archivo Ltd.10%

Immenso Enterprises

Ltd.

5%

Other minorities

33%

TGK-4


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 961 1 294 1 951 2 376 2 532 2 457 2 383 2 354 2 325 2 294 2 264 2 233 2 202 2 170 2 139

Non-cash WC 93 97 104 114 125 100 112 130 136 141 148 155 162 170 178

LT investments 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

Equity 770 842 1 516 1 577 1 826 2 047 2 272 2 580 2 961 3 355 3 765 4 193 4 639 5 104 5 590


Net debt (+) or cash (-) 201 460 447 826 745 426 141 - 178 - 583 -1 002 -1 436 -1 888 -2 358 -2 847 -3 355


Income statement*

Revenues 660 787 1 027 1 429 1 997 2 243 2 518 2 925 3 043 3 161 3 310 3 466 3 631 3 803 3 984

Electricity 311 353 486 729 1 154 1 253 1 352 1 571 1 669 1 726 1 814 1 907 2 006 2 110 2 219

Heat 322 403 505 663 804 949 1 124 1 310 1 328 1 388 1 446 1 508 1 571 1 638 1 707

Other 27 31 35 38 39 40 42 44 46 47 49 51 53 56 58

Cost of sales - 617 - 752 - 992 -1 251 -1 612 -1 889 -2 156 -2 502 -2 525 -2 626 -2 753 -2 887 -3 027 -3 175 -3 330

Fuel costs - 372 - 460 - 635 - 815 -1 075 -1 291 -1 537 -1 852 -1 837 -1 902 -1 991 -2 084 -2 182 -2 285 -2 393

D&A - 28 - 39 - 63 - 93 - 120 - 141 - 143 - 148 - 153 - 158 - 163 - 168 - 174 - 180 - 186

Fixed costs - 217 - 253 - 293 - 343 - 418 - 457 - 476 - 503 - 535 - 566 - 599 - 634 - 671 - 710 - 751

EBITDA 75 78 103 277 511 501 511 577 677 699 727 755 785 816 849

EBIT 47 39 40 184 391 359 368 429 524 542 564 587 611 637 663

EBT 34 20 20 164 371 340 350 410 506 523 545 568 593 618 644

Net income 25 15 15 125 282 259 266 312 384 397 414 432 450 470 490

EBITDA margin 11% 10% 10% 19% 26% 22% 20% 20% 22% 22% 22% 22% 22% 21% 21%

EBIT margin 7% 5% 4% 13% 20% 16% 15% 15% 17% 17% 17% 17% 17% 17% 17%

Net margin 4% 2% 1% 9% 14% 12% 11% 11% 13% 13% 13% 12% 12% 12% 12%

Cash flow statement

Change in WC - 42 3 - 5 - 15 - 13 23 - 14 - 18 - 5 - 5 - 7 - 7 - 7 - 8 - 8

OCF 14 76 94 223 408 442 413 460 550 568 589 612 635 660 686

Net capex - 89 - 292 - 683 - 607 - 324 - 115 - 116 - 119 - 123 - 127 - 132 - 137 - 142 - 148 - 154


ICF - 77 - 292 - 683 - 607 - 324 - 115 - 115 - 119 - 123 - 127 - 132 - 137 - 142 - 148 - 154


Change in debt 77 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 60 - 19 612 - 20 - 20 - 19 - 19 - 19 - 19 - 19 - 19 - 19 - 19 - 19 - 19

Net CF - 3 - 235 23 - 404 65 308 279 322 409 423 439 456 474 493 513


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.4 1.8 1.3 0.9 0.8 0.7 0.6 0.6 0.6 0.6 0.5 0.5 0.5 0.5

EV/EBITDA 24.1 18.3 6.8 3.7 3.8 3.7 3.3 2.8 2.7 2.6 2.5 2.4 2.3 2.2

P/E 137.2 136.5 16.4 7.2 7.9 7.7 6.6 5.3 5.1 4.9 4.7 4.5 4.4 4.2

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 16% 17% 17% 17% 17% 17% 18% 18% 18% 18% 18% 18% 19% 19% 19%

Total effective electricity

price, USD/MWh27 32 40 51 61 68 77 90 95 98 101 105 108 112 116

Fuel cost, USD/MWh 33 42 52 57 57 70 88 106 105 108 111 114 118 121 125

EBITDA/kW, USD 23 24 30 74 110 108 111 125 146 151 157 163 170 177 184

TGK-4


DCF



Valuation


EBIT 40 184 391 359 368 429 524 542 564 587 611 637 663

Tax on EBIT - 10 - 44 - 94 - 86 - 88 - 103 - 126 - 130 - 135 - 141 - 147 - 153 - 159

After tax EBIT 30 140 297 273 280 326 398 412 429 446 465 484 504

Depreciation 63 93 120 141 143 148 153 158 163 168 174 180 186

Capex - 683 - 607 - 324 - 115 - 116 - 119 - 123 - 127 - 132 - 137 - 142 - 148 - 154

Change in WC - 5 - 15 - 13 23 - 14 - 18 - 5 - 5 - 7 - 7 - 7 - 8 - 8

FCFF - 594 - 389 80 323 293 336 423 437 453 470 489 508 527

Discounted FCFF - 559 - 328 60 217 177 181 204 189 175 162 151 140 130

WACC 11.8%




Fair EV 2 259


Minority interest 0

Fair MCap 2 424

Common Preferred

FV, USD 0.00125 0.000623

Upside to FV, USD 19% 12%

12m TP, USD 0.00142 0.000707


Dividend yield 0.1% 0.5%

Expected total return over 12m 35% 28%


Shares outstanding, mn 1 907 202 75 273


WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.00175 0.00187 0.00202 0.00222 0.00249

10.8% 0.00149 0.00158 0.00169 0.00182 0.00200

11.8% 0.00127 0.00134 0.00142 0.00152 0.00164

12.8% 0.00110 0.00115 0.00121 0.00128 0.00137

13.8% 0.00095 0.00099 0.00103 0.00109 0.00115

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 951 1 022 1 110 1 225 1 379

10.8% 800 852 915 995 1 099

11.8% 677 716 763 820 892

12.8% 575 605 640 682 733

13.8% 490 513 539 571 609

Terminal growth


Belgorod 110 252 363 2 553 - 64 299 2 103

Bryansk 10 14 24 473 - 5 19 379

Voronezh 54 229 283 1 574 33 317 1 760

Kaluga - 13 1 - 12 - 975 - 1 - 13 -1 056

Kursk 29 165 194 986 26 220 1 116

Lipetsk 180 261 441 812 - 40 401 738

Orel 115 74 189 554 9 199 582

Ryazan 42 29 71 715 2 74 736

Smolensk 168 113 280 695 0 280 695

Tambov 83 80 163 517 0 163 517

Tula 345 253 598 582 - 29 570 554

TGK-4 total 1 123 1 472 2 595 784 - 68 2 527 763

Branch


Existing assets New

project Total USD/kW


TGK-5

Strengths Coal power plants in European Russia


6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Kirov Kirov 940 3 369 4 565 6 930

Mariy-El Mariy-El 195 660 1 025 970

Udmurtia Udmurtia 480 2 374 2 708 4 386

Chuvashia Chuvashia 852 2 637 2 725 4 386

TGK-5 total 2 467 9 040 11 023 16 672

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Kirov reconstruction with 70 MW and 140 MW CCGTs 2010 212 168 gas 227 44

Udmurtia reconstruction with 144 MW CCGT 2010 144 116 gas 156 36

Gas89%

Coal7%

Fuel oil1%

Peat3%

Gas69%

Coal23%Fuel oil

1%

Peat7%

UES65%

IES20%

Other minorities

15%

IES46% Russian

Federation25%

Gazprom5%

Other minorities

24%

TGK-5


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 405 477 692 857 897 887 876 881 886 890 894 898 903 908 913

Non-cash WC 55 60 58 58 62 51 55 64 69 72 76 80 84 89 94

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 395 891 887 877 988 1 109 1 243 1 434 1 670 1 913 2 166 2 430 2 706 2 994 3 294


Net debt (+) or cash (-) 28 - 394 - 178 - 2 - 68 - 209 - 349 - 526 - 752 - 988 -1 234 -1 489 -1 756 -2 034 -2 325


Income statement*

Revenues 416 515 602 752 1 023 1 135 1 239 1 435 1 552 1 625 1 708 1 797 1 890 1 989 2 102

Electricity 228 257 336 406 589 625 665 780 860 894 946 1 001 1 059 1 121 1 191

Heat 161 226 230 308 395 469 532 612 646 683 713 745 777 812 853

Other 27 31 36 38 39 40 42 44 46 47 49 51 53 56 58

Cost of sales - 407 - 505 - 632 - 717 - 852 - 949 -1 033 -1 183 -1 238 -1 303 -1 373 -1 447 -1 525 -1 608 -1 704

Fuel costs - 221 - 289 - 384 - 433 - 514 - 577 - 646 - 775 - 806 - 846 - 891 - 938 - 988 -1 040 -1 105

D&A - 14 - 19 - 29 - 42 - 54 - 64 - 66 - 69 - 72 - 75 - 78 - 81 - 85 - 89 - 92

Fixed costs - 173 - 196 - 219 - 242 - 284 - 309 - 321 - 339 - 361 - 382 - 404 - 428 - 452 - 479 - 506

EBITDA 24 32 1 79 227 253 275 325 389 400 417 435 454 474 495

EBIT 11 12 - 28 37 174 189 209 256 317 326 339 354 369 385 402

EBT 10 9 - 31 34 171 186 206 253 314 323 336 351 366 382 399

Net income 7 7 - 31 26 130 141 157 192 239 245 256 267 278 290 303

EBITDA margin 6% 6% 0% 11% 22% 22% 22% 23% 25% 25% 24% 24% 24% 24% 24%

EBIT margin 3% 2% neg 5% 17% 17% 17% 18% 20% 20% 20% 20% 20% 19% 19%

Net margin 2% 1% neg 3% 13% 12% 13% 13% 15% 15% 15% 15% 15% 15% 14%

Cash flow statement

Change in WC - 10 - 1 3 - 2 - 6 11 - 6 - 9 - 5 - 3 - 4 - 4 - 4 - 4 - 5

OCF 8 29 12 69 181 219 220 255 308 320 333 347 362 377 394

Net capex - 19 - 60 - 231 - 238 - 111 - 72 - 72 - 74 - 76 - 79 - 82 - 86 - 90 - 93 - 98


ICF - 19 - 60 - 231 - 238 - 111 - 72 - 72 - 74 - 76 - 79 - 82 - 86 - 90 - 93 - 98


Change in debt 17 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 10 438 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3

Net CF - 1 407 - 222 - 172 67 144 145 178 229 238 248 258 269 281 293


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.1 0.9 0.7 0.5 0.5 0.5 0.4 0.4 0.3 0.3 0.3 0.3 0.3 0.3

EV/EBITDA 17.7 420.9 7.0 2.5 2.2 2.0 1.7 1.4 1.4 1.3 1.3 1.2 1.2 1.1

P/E 134.3 neg 36.7 7.4 6.8 6.1 5.0 4.0 3.9 3.7 3.6 3.4 3.3 3.1

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 21% 21% 21% 21% 22% 22% 22% 22% 23% 23% 23% 23% 24% 24% 24%


USD/MWh25 26 34 41 53 58 67 78 86 89 92 95 98 101 104

Fuel cost, USD/MWh 24 30 39 44 46 54 65 78 81 84 87 89 91 94 97

EBITDA/kW, USD 10 13 1 32 81 90 98 116 139 143 149 155 162 169 176

TGK-5


DCF

12m target price


Valuation


EBIT - 28 37 174 189 209 256 317 326 339 354 369 385 402

Tax on EBIT 7 - 9 - 42 - 45 - 50 - 61 - 76 - 78 - 81 - 85 - 89 - 92 - 97

After tax EBIT - 21 28 132 143 159 194 241 247 258 269 280 293 306

Depreciation 29 42 54 64 66 69 72 75 78 81 85 89 92

Capex - 231 - 238 - 111 - 72 - 72 - 74 - 76 - 79 - 82 - 86 - 90 - 93 - 98

Change in WC 3 - 2 - 6 11 - 6 - 9 - 5 - 3 - 4 - 4 - 4 - 4 - 5

FCFF - 220 - 170 69 146 148 180 231 240 250 261 272 283 295

Discounted FCFF - 207 - 143 52 99 89 97 111 104 96 90 84 78 73

WACC 11.8%




Fair EV 1 384

Net debt 2007e 394

Minority interest 0

Fair MCap 1 778


Upside to FV 87%

12m TP, USD 0.00165

Upside to TP 112%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.00194 0.00204 0.00218 0.00236 0.00259

10.8% 0.00170 0.00178 0.00188 0.00200 0.00216

11.8% 0.00152 0.00157 0.00165 0.00173 0.00184

12.8% 0.00136 0.00140 0.00146 0.00152 0.00160

13.8% 0.00123 0.00126 0.00130 0.00135 0.00141

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 768 821 888 974 1 090

10.8% 655 694 742 802 880

11.8% 563 592 627 670 724

12.8% 487 509 535 567 605

13.8% 423 440 460 483 512

Terminal growth


Kirov 394 197 592 629 49 641 681

Mariy-El 83 32 115 590 0 115 590

Udmurtia 220 119 339 706 40 379 789

Chuvashia 255 159 414 486 0 414 486

TGK-5 total 952 508 1 460 592 89 1 548 628

Branch


Existing assets New



TGK-6



6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity,

MW

Installed heat

capacity,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Ivanovo Ivanovo 523 2 213 1 888 2 506

Vladimir Vladimir 407 1 161 2 087 2 047

Nizhny Novgorod Nizhny Novgorod 789 2 154 2 838 3 778

Mordovia Mordovia 349 1 190 1 510 2 175

Penza Penza 405 2 136 1 673 3 698

Dzerzhinsk Nizhny Novgorod 667 1 971 2 502 2 607

TGK-6 total 3 140 10 824 12 499 16 811

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Ivanovo reconstruction 2007 19 0 gas 20 18

Nizhny Novgorod3 new 325 MW CCGT power plant and

reconstruction of old capacity2010 985 1 129 gas 1 171 - 60

Dzerzhinsk reconstruction 2010 135 358 gas 148 31

Gas95%

Coal3%

Fuel oil2%

Gas95%

Coal3%

Fuel oil2%

UES50%

Archivo Ltd.

19%

IES19%

Other minorities

12%

Archivo Ltd.

19%

IES and affiliated

64%

Other minorities

17%

TGK-6


Financials

Financial ratios

Operational data

USD mn 2006e 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Balance sheet

Fixed assets 459 536 626 839 1 062 1 264 1 443 1 652 1 858 1 862 1 865 1 869 1 873 1 877 1 880

Non-cash WC 15 21 29 37 46 67 76 97 102 114 120 126 132 138 145

LT investments 162 173 177 170 167 164 161 161 161 161 161 161 161 161 161

Equity 604 631 1 189 1 149 1 160 1 270 1 405 1 635 1 924 2 257 2 604 2 966 3 342 3 733 4 141


Net debt (+) or cash (-) 104 177 - 278 - 27 189 297 346 347 268 - 49 - 387 - 738 -1 105 -1 486 -1 884

Other LT liabilities (+) or assets (-) - 72 - 78 - 79 - 76 - 75 - 73 - 72 - 72 - 72 - 72 - 72 - 72 - 72 - 72 - 72

Income statement

Revenues 548 651 830 1 000 1 118 1 496 1 704 2 170 2 285 2 566 2 688 2 817 2 953 3 096 3 246

Electricity 295 339 441 518 552 836 928 1 247 1 341 1 552 1 633 1 718 1 808 1 902 2 002

Heat 224 280 351 442 525 617 732 877 895 964 1 004 1 046 1 089 1 135 1 182

Other 29 33 37 40 41 42 44 46 48 50 52 54 56 59 61

Cost of sales - 559 - 637 - 833 - 950 -1 032 -1 277 -1 450 -1 822 -1 855 -2 076 -2 179 -2 287 -2 402 -2 522 -2 649

Fuel costs - 344 - 396 - 556 - 635 - 684 - 876 -1 025 -1 343 -1 339 -1 502 -1 573 -1 648 -1 727 -1 810 -1 897

D&A - 39 - 41 - 46 - 52 - 58 - 62 - 72 - 83 - 95 - 103 - 108 - 112 - 117 - 122 - 127

Fixed costs - 177 - 200 - 231 - 263 - 290 - 339 - 353 - 395 - 421 - 471 - 498 - 527 - 558 - 590 - 624

EBITDA 7 31 15 73 114 249 294 398 490 557 580 603 627 653 680

EBIT - 32 - 10 - 30 21 56 187 222 315 395 454 472 491 510 531 553

EBT - 39 - 21 - 42 10 45 176 211 305 384 443 461 480 500 520 542

Net income - 39 - 21 - 42 8 34 134 160 231 292 337 350 365 380 395 412

EBITDA margin 1% 5% 2% 7% 10% 17% 17% 18% 21% 22% 22% 21% 21% 21% 21%



Cash flow statement

Change in WC - 4 - 4 - 7 - 10 - 10 - 22 - 11 - 21 - 5 - 13 - 5 - 6 - 6 - 6 - 7

OCF 26 32 18 61 93 185 232 304 393 438 463 482 501 522 543

Net capex - 22 - 84 - 122 - 294 - 300 - 287 - 277 - 294 - 303 - 107 - 112 - 116 - 121 - 126 - 131


ICF - 5 - 83 - 120 - 293 - 299 - 285 - 275 - 293 - 302 - 106 - 110 - 115 - 120 - 125 - 130


Change in debt 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 30 - 12 557 - 13 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12

Net CF - 9 - 63 454 - 245 - 218 - 113 - 55 0 79 320 341 355 370 385 401


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.5 1.2 1.0 0.9 0.6 0.6 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3

EV/EBITDA 31.3 62.7 13.3 8.5 3.9 3.3 2.4 2.0 1.7 1.7 1.6 1.5 1.5 1.4

P/E neg neg 178.7 40.0 10.1 8.5 5.9 4.7 4.0 3.9 3.7 3.6 3.4 3.3

2006e 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e





Heat sales, thous.Gcal 18 004 16 811 17 543 18 244 18 421 19 438 19 613 20 439 20 617 21 446 21 628 21 811 21 997 22 184 22 374

Load factor (heat) 18% 18% 18% 18% 19% 19% 19% 20% 20% 20% 20% 20% 21% 21% 21%


USD/MWh25 31 38 45 53 66 79 89 96 96 99 102 105 109 113

Fuel cost, USD/MWh 29 36 48 55 66 69 87 96 95 93 95 98 101 104 107

EBITDA/kW, USD 2 10 5 23 36 70 83 103 127 133 138 144 150 156 162

TGK-6


DCF

12m target price


Valuation


EBIT - 30 21 56 187 222 315 395 454 472 491 510 531 553

Tax on EBIT 7 - 5 - 13 - 45 - 53 - 76 - 95 - 109 - 113 - 118 - 122 - 127 - 133

After tax EBIT - 23 16 42 142 169 240 300 345 359 373 388 404 420

Depreciation 46 52 58 62 72 83 95 103 108 112 117 122 127

Capex - 122 - 294 - 300 - 287 - 277 - 294 - 303 - 107 - 112 - 116 - 121 - 126 - 131

Change in WC - 7 - 10 - 10 - 22 - 11 - 21 - 5 - 13 - 5 - 6 - 6 - 6 - 7

FCFF - 107 - 236 - 209 - 105 - 47 8 87 328 349 363 378 393 409

Discounted FCFF - 100 - 199 - 158 - 70 - 28 4 42 142 135 125 117 109 101

WACC 11.8%




Fair EV 1 274


Minority interest 0

Fair MCap 1 660


Upside to FV 22%

12m TP, USD 0.00102

Upside to TP 39%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.00124 0.00134 0.00147 0.00163 0.00185

10.8% 0.00105 0.00112 0.00121 0.00133 0.00147

11.8% 0.00090 0.00095 0.00102 0.00110 0.00120

12.8% 0.00077 0.00081 0.00086 0.00092 0.00099

13.8% 0.00067 0.00070 0.00074 0.00078 0.00084

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 585 643 715 809 936

10.8% 473 516 568 633 718

11.8% 384 415 454 501 559

12.8% 311 335 364 398 440

13.8% 251 270 291 317 348

Terminal growth


Ivanovo 66 100 166 318 20 187 357

Vladimir 183 69 252 619 0 252 619

Nizhny Novgorod 202 177 379 480 - 67 311 394

Mordovia 103 81 184 527 0 184 527

Penza 104 138 242 597 0 242 597

Dzerzhinsk 149 67 216 324 35 251 376

TGK-6 total 807 631 1 438 458 - 12 1 426 454

Branch


Existing assets New



TGK-7



6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity

2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat

sales

2007,

k GCal

Samara Samara 3 520 16 652 13 617 23 232

Saratov Saratov 1 479 6 065 5 163 7 022

Orenburg Orenburg 1 029 5 010 4 922 9 574

Ulyanovsk Ulyanovsk 852 3 415 2 970 4 192

TGK-7 total 6 880 31 143 26 673 44 020

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Samaranew 200 MW CCGT capacity and

reconstruction of old capacity2011 445 453 gas 486 - 20

Gas99.7%

Fuel oil0.3%

Gas99.2%

Fuel oil0.8%

UES54%

Estone Holdings

Ltd.

8%Emeraldi

Enterprises Ltd.

8%Rubinium

Enterprises Ltd.

8%Prosperity Capital19%

Other minorities

3%

IES 56%

Prosperity Capital16%

Other minorities

28%

TGK-7


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 1 351 1 473 1 645 1 934 2 045 2 072 2 096 2 158 2 218 2 278 2 337 2 397 2 457 2 517 2 578

Non-cash WC 84 181 115 125 137 146 170 200 211 220 231 242 254 267 281

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 1 152 1 255 1 751 1 800 1 994 2 265 2 640 3 156 3 822 4 510 5 226 5 970 6 745 7 552 8 391


Net debt (+) or cash (-) 69 168 - 226 33 - 34 - 264 - 586 -1 012 -1 606 -2 226 -2 871 -3 544 -4 247 -4 980 -5 746


Income statement*

Revenues 1 224 1 516 1 961 2 375 2 813 3 282 3 823 4 482 4 731 4 927 5 173 5 433 5 707 5 994 6 296

Electricity 531 679 886 1 082 1 330 1 602 1 854 2 207 2 416 2 508 2 652 2 805 2 967 3 138 3 320

Heat 580 717 937 1 146 1 332 1 524 1 807 2 105 2 137 2 235 2 329 2 428 2 532 2 639 2 751

Other 113 121 138 147 152 157 162 170 177 185 192 200 208 216 225

Cost of sales -1 210 -1 451 -1 912 -2 196 -2 490 -2 853 -3 251 -3 778 -3 828 -3 996 -4 205 -4 426 -4 659 -4 905 -5 163

Fuel costs - 659 - 793 -1 188 -1 394 -1 604 -1 900 -2 259 -2 730 -2 713 -2 816 -2 956 -3 105 -3 262 -3 427 -3 599

D&A - 92 - 103 - 104 - 112 - 114 - 109 - 114 - 121 - 128 - 136 - 144 - 152 - 161 - 170 - 179

Fixed costs - 459 - 554 - 620 - 690 - 772 - 844 - 878 - 927 - 987 -1 044 -1 105 -1 169 -1 237 -1 308 -1 384

EBITDA 110 169 153 291 437 537 685 825 1 030 1 067 1 112 1 159 1 208 1 259 1 312

EBIT 18 66 48 179 323 429 571 704 902 931 968 1 006 1 047 1 089 1 133

EBT 14 54 30 160 305 411 554 686 885 914 950 989 1 029 1 071 1 115

Net income 11 41 23 122 232 312 421 522 672 694 722 752 782 814 848

EBITDA margin 9% 11% 8% 12% 16% 16% 18% 18% 22% 22% 21% 21% 21% 21% 21%

EBIT margin 1% 4% 2% 8% 11% 13% 15% 16% 19% 19% 19% 19% 18% 18% 18%

Net margin 1% 3% 1% 5% 8% 10% 11% 12% 14% 14% 14% 14% 14% 14% 13%

Cash flow statement

Change in WC - 63 - 91 69 - 15 - 15 - 12 - 27 - 30 - 11 - 9 - 11 - 12 - 12 - 13 - 14

OCF 21 53 214 237 349 427 525 630 807 839 873 910 948 989 1 031

Net capex - 88 - 129 - 242 - 473 - 264 - 176 - 177 - 183 - 189 - 196 - 204 - 212 - 221 - 231 - 241


ICF - 75 - 126 - 241 - 473 - 264 - 176 - 177 - 182 - 189 - 195 - 203 - 212 - 221 - 230 - 240


Change in debt 82 82 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 77 66 420 - 19 - 19 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18

Net CF 23 - 6 393 - 255 67 233 330 430 600 626 651 680 709 740 773


2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.6 1.2 1.0 0.9 0.7 0.6 0.5 0.5 0.5 0.5 0.4 0.4 0.4 0.4

EV/EBITDA 14.4 15.9 8.4 5.6 4.5 3.6 2.9 2.4 2.3 2.2 2.1 2.0 1.9 1.9

P/E 65.5 119.7 22.2 11.6 8.6 6.4 5.2 4.0 3.9 3.7 3.6 3.4 3.3 3.2

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 17% 16% 16% 16% 17% 17% 17% 17% 17% 18% 18% 18% 18% 18% 18%


USD/MWh22 29 37 45 55 66 81 96 105 108 111 115 118 122 125

Fuel cost, USD/MWh 28 34 50 58 66 79 99 119 118 121 124 127 130 133 136

EBITDA/kW, USD 16 25 22 42 60 73 94 113 141 146 152 158 165 172 179

TGK-7


DCF

12m target price


Valuation


EBIT 48 179 323 429 571 704 902 931 968 1 006 1 047 1 089 1 133

Tax on EBIT - 12 - 43 - 77 - 103 - 137 - 169 - 216 - 223 - 232 - 242 - 251 - 261 - 272

After tax EBIT 37 136 245 326 434 535 685 708 736 765 795 827 861

Depreciation 104 112 114 109 114 121 128 136 144 152 161 170 179

Capex - 242 - 473 - 264 - 176 - 177 - 183 - 189 - 196 - 204 - 212 - 221 - 231 - 241

Change in WC 69 - 15 - 15 - 12 - 27 - 30 - 11 - 9 - 11 - 12 - 12 - 13 - 14

FCFF - 32 - 241 80 247 343 443 613 639 665 693 723 754 786

Discounted FCFF - 30 - 203 60 166 207 239 296 276 256 239 223 208 194

WACC 11.8%




Fair EV 4 158

Net debt 2007 (adj. for SPO in 2008) 266

Minority interest 0

Fair MCap 4 425

FV of common shares, USD 0.148

Upside to FV 64%

12m TP, USD 0.168

Upside to TP 87%

Dividend yield 0.1%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.199 0.211 0.226 0.245 0.271

10.8% 0.174 0.183 0.194 0.207 0.224

11.8% 0.154 0.160 0.168 0.178 0.190

12.8% 0.137 0.142 0.148 0.155 0.163

13.8% 0.123 0.126 0.131 0.136 0.143

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 810 860 924 1 006 1 117

10.8% 702 739 785 842 916

11.8% 614 642 676 717 768

12.8% 542 563 588 618 655

13.8% 481 497 516 539 566

Terminal growth


Samara 902 1 319 2 221 631 - 22 2 199 625

Saratov 355 476 831 562 0 831 562

Orenburg 622 516 1 138 1 106 0 1 138 1 106

Ulyanovsk 221 262 483 567 0 483 567

TGK-7 total 2 100 2 574 4 673 679 - 22 4 651 676

Branch


Existing assets New



TGK-8

Strengths Favourable heat business regulation




6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-20%

-10%

0%

10%

20%

30%

40%


Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Astrakhan Astrakhan 480 1 834 2 924 1 836

Volgograd Volgograd 1 501 5 880 3 762 6 758

Dagestan Dagestan 44 527 91 665

Kuban Krasnodar 696 856 5 297 978

Rostov City Rostov 160 1 814 759 2 547

Rostov Region Rostov 460 2 198 1 029 919

Stavropol Stavropol 12 272 28 204

Hydro Krasnodar/Rostov 249 0 852 0

TGK-8 total 3 602 13 381 14 743 13 908

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Astrakhannew 410 MW CCGT

and reconstruction with 110 MW CCGT2010 520 0 gas 565 192

Volgograd reconstruction with 180 MW CCGT 2014 180 0 gas 215 - 5

Kuban reconstruction with new 410 MW CCGT 2010 410 0 gas 445 - 3

Gas99.9%

Fuel oil

0.1%

Gas98.9%

Fuel oil

1.1%

UES64%

Promregionholding17%

Energostrategia19%

Other minorities

18%

Lukoil82%

TGK-8


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 512 600 1 050 1 423 1 609 1 634 1 657 1 709 1 688 1 666 1 644 1 622 1 599 1 577 1 555

Non-cash WC 64 67 74 74 86 73 81 94 102 106 111 116 122 128 134

LT investments 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

Equity 396 1 362 1 392 1 390 1 593 1 788 1 975 2 235 2 578 2 932 3 303 3 691 4 097 4 522 4 965

Minority interest 0 0 0 - 1 - 4 - 8 - 14 - 21 - 30 - 40 - 50 - 61 - 72 - 84 - 97

Net debt (+) or cash (-) 117 - 761 - 335 40 34 - 152 - 312 - 514 - 879 -1 262 -1 660 -2 075 -2 509 -2 962 -3 435


Income statement*

Revenues 519 618 814 1 016 1 457 1 631 1 820 2 111 2 287 2 374 2 487 2 606 2 732 2 864 3 001

Electricity 309 363 500 623 994 1 095 1 197 1 399 1 557 1 610 1 691 1 777 1 868 1 963 2 063

Heat 184 224 279 357 425 496 582 670 685 717 748 779 812 846 882

Other 26 30 34 37 38 39 40 42 44 46 48 50 52 54 56

Cost of sales - 534 - 631 - 814 - 941 -1 148 -1 327 -1 490 -1 716 -1 769 -1 841 -1 934 -2 032 -2 136 -2 245 -2 359

Fuel costs - 313 - 369 - 504 - 574 - 695 - 819 - 962 -1 158 -1 176 -1 217 -1 276 -1 340 -1 406 -1 476 -1 550

D&A - 17 - 25 - 42 - 65 - 89 - 111 - 115 - 122 - 128 - 132 - 137 - 142 - 146 - 151 - 157

Fixed costs - 205 - 237 - 269 - 302 - 363 - 397 - 413 - 436 - 465 - 492 - 521 - 551 - 583 - 617 - 652

EBITDA 10 23 53 153 411 428 459 532 661 681 706 732 760 789 817

EBIT - 7 - 3 11 88 322 317 343 409 533 548 569 591 614 637 661

EBT - 14 - 15 - 2 75 309 305 331 397 521 536 557 579 602 626 649

Net income - 14 - 14 - 2 55 226 223 220 259 342 354 370 387 405 424 444

EBITDA margin 2% 4% 6% 15% 28% 26% 25% 25% 29% 29% 28% 28% 28% 28% 27%

EBIT margin neg neg 1% 9% 22% 19% 19% 19% 23% 23% 23% 23% 22% 22% 22%


Cash flow statement

Change in WC - 40 1 - 5 - 4 - 14 12 - 10 - 13 - 8 - 4 - 5 - 5 - 6 - 6 - 6

OCF - 40 27 48 131 323 367 346 391 487 508 528 551 574 598 623

Net capex - 21 - 74 - 474 - 488 - 305 - 167 - 170 - 175 - 107 - 110 - 115 - 119 - 124 - 129 - 134


ICF - 15 - 74 - 474 - 488 - 305 - 167 - 170 - 175 - 107 - 110 - 115 - 119 - 124 - 129 - 134


Change in debt 81 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 67 898 - 13 - 13 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12 - 12

Net CF 12 851 - 438 - 369 5 188 164 204 369 386 402 419 438 458 477


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 4.5 3.4 2.7 1.9 1.7 1.5 1.3 1.2 1.2 1.1 1.1 1.0 1.0 0.9

EV/EBITDA 122.8 52.6 18.1 6.7 6.5 6.0 5.2 4.2 4.1 3.9 3.8 3.6 3.5 3.4

P/E neg neg 62.4 15.2 15.4 15.6 13.2 10.0 9.7 9.3 8.9 8.5 8.1 7.7

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 12% 12% 12% 12% 12% 12% 12% 13% 13% 13% 13% 13% 13% 13% 14%


USD/MWh22 27 35 44 57 65 74 87 91 94 97 101 104 107 111

Fuel cost, USD/MWh 23 28 35 40 40 48 60 72 69 71 73 76 78 81 83

EBITDA/kW, USD 3 6 15 42 96 100 108 125 155 160 166 172 178 185 192

TGK-8


DCF

12m target price


Valuation


EBIT 11 88 322 317 343 409 533 548 569 591 614 637 661

Tax on EBIT - 3 - 21 - 77 - 76 - 107 - 132 - 169 - 172 - 176 - 180 - 184 - 188 - 191

After tax EBIT 8 67 245 241 237 278 364 376 393 411 430 449 469

Depreciation 42 65 89 111 115 122 128 132 137 142 146 151 157

Capex - 474 - 488 - 305 - 167 - 170 - 175 - 107 - 110 - 115 - 119 - 124 - 129 - 134

Change in WC - 5 - 4 - 14 12 - 10 - 13 - 8 - 4 - 5 - 5 - 6 - 6 - 6

FCFF - 428 - 360 15 197 173 212 377 394 410 428 446 466 486

Discounted FCFF - 403 - 303 11 133 104 114 182 170 158 148 138 129 120

WACC 11.8%




Fair EV 1 953

Net debt 2007e 761

LT investments 29


Fair MCap 2 644


Upside to FV -23%

12m TP, USD 0.00146

Upside to TP -12%

Dividend yield 0.0%

Expected total return over 12m -12%



WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.00174 0.00184 0.00198 0.00215 0.00238

10.8% 0.00151 0.00159 0.00169 0.00181 0.00196

11.8% 0.00133 0.00139 0.00146 0.00155 0.00166

12.8% 0.00118 0.00123 0.00128 0.00134 0.00142

13.8% 0.00106 0.00109 0.00113 0.00118 0.00124

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 760 820 895 992 1 123

10.8% 635 679 733 800 888

11.8% 534 567 606 655 716

12.8% 450 475 505 540 584

13.8% 380 400 422 449 481

Terminal growth


Astrakhan 133 88 221 461 215 436 908

Volgograd 250 401 650 433 - 5 645 430

Dagestan 6 40 46 1 041 0 46 1 041

Kuban 432 30 461 663 - 3 459 659

Rostov City 52 182 234 1 460 0 234 1 460

Rostov Region - 5 43 38 83 0 38 83

Stavropol - 1 22 21 1 745 0 21 1 745

Hydro 305 0 305 1 224 0 305 1 224

TGK-8 total 1 171 805 1 976 549 207 2 183 606

Branch


Existing assets New



TGK-9


Above-average heat load factor

Coal plants in European Russia


6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Perm Perm 1 359 6 806 7 107 15 800

Sverdlovsk Sverdlovsk 1 230 7 242 6 355 19 900

Komi Komi 690 2 400 2 832 5 800

TGK-9 total 3 280 16 448 16 294 41 500

Branch Project name

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Permnew 418 MW CCGT and reconstruction

of old capacity2012 800.7 844 gas 904 137

Sverdlovsk new 1041 MW CCGT 2015 1 041 1 120 gas 1 247 83

Gas81%

Coal17%

Fuel oil2%

Gas82%

Coal16%

Fuel oil2%

UES50%

BNP Paribas

Securities

Services 15%

IES and

af f iliated

19%

Other minorities

16%

IES and

af f iliated

76%

Other minorities

24%

TGK-9


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 644 742 846 1 105 1 595 2 083 2 399 2 663 2 980 2 993 3 007 3 020 3 032 3 044 3 056

Non-cash WC 285 290 286 250 182 103 136 162 174 187 196 206 215 226 237

LT investments 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Equity 748 1 508 1 612 1 691 1 800 1 956 2 256 2 669 3 171 3 721 4 292 4 887 5 505 6 149 6 819


Net debt (+) or cash (-) 176 - 481 - 484 - 340 - 28 226 275 152 - 22 - 544 -1 093 -1 666 -2 262 -2 883 -3 530


Income statement

Revenues 946 1 148 1 466 1 778 1 950 2 314 3 052 3 639 3 899 4 206 4 404 4 613 4 833 5 064 5 307

Electricity 421 491 634 766 785 974 1 427 1 745 1 944 2 138 2 244 2 356 2 474 2 598 2 730

Heat 480 605 773 949 1 099 1 273 1 556 1 822 1 879 1 988 2 078 2 172 2 270 2 373 2 481

Other 45 52 60 63 65 68 70 73 76 79 83 86 90 93 97

Cost of sales - 849 -1 068 -1 333 -1 541 -1 716 -2 017 -2 558 -3 044 -3 184 -3 426 -3 594 -3 771 -3 958 -4 154 -4 361

Fuel costs - 497 - 650 - 872 -1 030 -1 152 -1 388 -1 836 -2 255 -2 320 -2 489 -2 604 -2 726 -2 854 -2 989 -3 130

D&A - 18 - 44 - 49 - 56 - 70 - 85 - 104 - 121 - 138 - 151 - 157 - 164 - 171 - 179 - 187

Fixed costs - 334 - 375 - 411 - 455 - 493 - 544 - 618 - 667 - 726 - 787 - 833 - 881 - 932 - 986 -1 044

EBITDA 96 103 158 267 278 354 569 687 822 898 934 971 1 010 1 051 1 094

EBIT 78 58 109 211 208 270 465 566 684 747 776 807 839 872 907

EBT 71 41 91 192 190 252 448 549 667 730 759 790 822 855 890

Net income 54 31 69 146 144 192 341 417 507 555 577 600 625 650 676

EBITDA margin 10% 9% 11% 15% 14% 15% 19% 19% 21% 21% 21% 21% 21% 21% 21%

EBIT margin 8% 5% 7% 12% 11% 12% 15% 16% 18% 18% 18% 17% 17% 17% 17%

Net margin 6% 3% 5% 8% 7% 8% 11% 11% 13% 13% 13% 13% 13% 13% 13%

Cash flow statement

Change in WC - 21 15 10 25 64 76 - 35 - 26 - 12 - 14 - 9 - 9 - 10 - 10 - 11

OCF 1 108 147 246 296 370 427 529 651 709 742 772 803 836 869

Net capex - 65 - 93 - 135 - 355 - 587 - 609 - 463 - 388 - 458 - 164 - 171 - 177 - 184 - 191 - 199

Acquisitions/divestments 0 - 6 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 78 - 99 - 134 - 354 - 586 - 608 - 461 - 387 - 457 - 163 - 170 - 176 - 183 - 190 - 198


Change in debt 58 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 58 627 - 20 - 20 - 19 - 19 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18 - 18


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.6 1.3 1.0 1.0 0.8 0.6 0.5 0.5 0.4 0.4 0.4 0.4 0.4 0.4

EV/EBITDA 18.2 11.8 7.0 6.7 5.3 3.3 2.7 2.3 2.1 2.0 1.9 1.8 1.8 1.7

P/E 75.9 34.1 16.1 16.3 12.2 6.9 5.6 4.6 4.2 4.1 3.9 3.8 3.6 3.5

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 28% 29% 29% 29% 30% 30% 30% 30% 30% 31% 31% 31% 31% 32% 32%


USD/MWh31 35 44 50 56 65 73 84 88 90 93 96 99 103 107

Fuel cost, USD/MWh 36 47 60 67 82 92 94 108 104 104 108 111 115 118 122

EBITDA/kW, USD 29 31 48 78 81 97 129 149 171 178 185 192 200 208 217

TGK-9


DCF

12m target price


Valuation


EBIT 109 211 208 270 465 566 684 747 776 807 839 872 907

Tax on EBIT - 26 - 51 - 50 - 65 - 112 - 136 - 164 - 179 - 186 - 194 - 201 - 209 - 218

After tax EBIT 83 160 158 205 354 430 520 568 590 613 638 663 689

Depreciation 49 56 70 85 104 121 138 151 157 164 171 179 187

Capex - 135 - 355 - 587 - 609 - 463 - 388 - 458 - 164 - 171 - 177 - 184 - 191 - 199

Change in WC 10 25 64 76 - 35 - 26 - 12 - 14 - 9 - 9 - 10 - 10 - 11

FCFF 7 - 113 - 295 - 243 - 40 137 189 540 568 591 615 640 667

Discounted FCFF 7 - 95 - 222 - 164 - 24 74 91 233 219 204 190 177 165

WACC 11.8%




Fair EV 2 571

Net debt 2007e 481

Minority interest 0

Fair MCap 3 052


Upside to FV 30%

12m TP, USD 0.000439

Upside to TP 46%

Dividend yield 1.9%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 0.000529 0.000568 0.000616 0.000679 0.000763

10.8% 0.000454 0.000482 0.000516 0.000560 0.000616

11.8% 0.000393 0.000414 0.000439 0.000470 0.000510

12.8% 0.000343 0.000359 0.000378 0.000401 0.000429

13.8% 0.000302 0.000314 0.000329 0.000346 0.000367

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.8% 1 088 1 177 1 291 1 437 1 634

10.8% 910 976 1 057 1 159 1 291

11.8% 767 817 876 949 1 041

12.8% 651 689 733 787 853

13.8% 555 584 618 658 707

Terminal growth


Perm 493 643 1 136 836 153 1 290 949

Sverdlovsk 473 784 1 258 1 022 93 1 350 1 098

Komi - 64 300 236 343 0 236 343

TGK-9 total 903 1 727 2 630 802 246 2 876 877

Branch


Existing assets New



TGK-10





6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%


Branch Region

Installed

electric

capacity 2007,

MW

Installed

heat

capacity

2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales 2007,

k GCal

Chelyabinsk Chelyabinsk 1 094 6 277 6 890 12 138

Tyumen Tyumen 1 679 6 278 11 906 9 282

Kurgan Kurgan 480 2 016 1 931 2 501

Khantymansiysk Khantymansiysk 0 0 0 0

TGK-10 total 3 253 14 571 20 727 23 922

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Chelyabinsk new 220 MW CCGT 2010 220 146 gas 239 52

Tyumennew 450 MW CCGT, new 210 MW turbine,

reconstruction with 190 MW CCGT2012 850 435 gas 939 309

Khantymansiysk new plant with 3x400 MW CCGTs 2012 1 200 380 gas 1 342 653

Gas93.91%

Coal6.04%

Fuel oil

0.05%

Gas94.46%

Coal5.49%

Fuel oil

0.04%

UES82%

Russian Federation

6%Renaissance Securities

Ltd.

7%

Other minorities

5%

Fortum76%

Other minorities

17%Renaissance

Securities Ltd.

4%

Russian Federation

3%

TGK-10


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 706 799 1 449 2 124 2 611 2 992 3 137 3 137 3 136 3 134 3 132 3 129 3 127 3 125 3 123

Non-cash WC 113 124 122 132 130 102 129 148 155 161 169 177 186 195 204

LT investments 29 31 31 30 30 29 28 28 28 28 28 28 28 28 28

Equity 816 926 2 868 2 914 3 161 3 461 3 888 4 453 5 111 5 788 6 492 7 224 7 985 8 775 9 598


Net debt (+) or cash (-) 32 25 -1 269 - 633 - 400 - 350 - 611 -1 162 -1 822 -2 504 -3 211 -3 946 -4 710 -5 505 -6 330


Income statement*

Revenues 685 864 1 053 1 474 1 925 2 286 2 885 3 325 3 486 3 620 3 792 3 973 4 164 4 364 4 575

Electricity 383 477 614 898 1 221 1 459 1 900 2 192 2 329 2 410 2 530 2 658 2 792 2 934 3 084

Heat 253 329 374 507 633 753 909 1 054 1 073 1 124 1 172 1 222 1 274 1 329 1 386

Other 50 57 65 69 71 74 76 80 83 87 90 94 98 102 106

Cost of sales - 637 - 786 - 990 -1 241 -1 501 -1 788 -2 211 -2 552 -2 586 -2 694 -2 829 -2 973 -3 124 -3 283 -3 450

Fuel costs - 330 - 431 - 579 - 744 - 917 -1 141 -1 479 -1 777 -1 764 -1 827 -1 915 -2 009 -2 107 -2 210 -2 319

D&A - 49 - 53 - 74 - 106 - 125 - 131 - 146 - 156 - 163 - 169 - 176 - 183 - 191 - 198 - 206

Fixed costs - 258 - 302 - 337 - 392 - 459 - 517 - 586 - 619 - 659 - 698 - 738 - 781 - 826 - 874 - 925

EBITDA 90 124 129 330 540 619 811 919 1 052 1 085 1 127 1 172 1 218 1 267 1 318

EBIT 42 71 55 224 414 488 665 763 889 915 951 989 1 028 1 069 1 111

EBT 37 66 51 219 410 484 660 758 885 911 947 984 1 023 1 064 1 107

Net income 29 49 38 163 305 361 492 565 659 679 706 733 763 793 825

EBITDA margin 13% 14% 12% 22% 28% 27% 28% 28% 30% 30% 30% 29% 29% 29% 29%

EBIT margin 6% 8% 5% 15% 22% 21% 23% 23% 26% 25% 25% 25% 25% 24% 24%

Net margin 4% 6% 4% 11% 16% 16% 17% 17% 19% 19% 19% 18% 18% 18% 18%

Cash flow statement

Change in WC - 14 - 2 5 - 15 - 1 26 - 29 - 20 - 7 - 6 - 8 - 8 - 9 - 9 - 9

OCF 78 106 122 262 440 528 624 717 832 860 892 927 964 1 002 1 042

Net capex - 85 - 93 - 698 - 854 - 659 - 566 - 349 - 157 - 162 - 167 - 174 - 181 - 188 - 196 - 204


ICF - 85 - 93 - 698 - 854 - 659 - 566 - 349 - 157 - 162 - 167 - 174 - 181 - 188 - 196 - 204


Change in debt 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 4 - 5 1 857 - 5 - 5 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4

Net CF - 11 9 1 280 - 597 - 223 - 42 270 556 666 689 714 742 771 802 834


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.7 2.2 1.6 1.2 1.0 0.8 0.7 0.7 0.6 0.6 0.6 0.6 0.5 0.5

EV/EBITDA 18.9 18.1 7.1 4.3 3.8 2.9 2.5 2.2 2.2 2.1 2.0 1.9 1.8 1.8

P/E 82.3 107.6 24.8 13.3 11.2 8.2 7.2 6.1 6.0 5.7 5.5 5.3 5.1 4.9

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 20% 19% 20% 21% 21% 21% 21% 21% 22% 22% 22% 22% 22% 23% 23%


USD/MWh23 26 33 44 55 60 68 78 83 86 88 91 94 97 100

Fuel cost, USD/MWh 20 23 31 37 41 47 53 64 63 65 67 69 71 73 76

EBITDA/kW, USD 29 38 40 90 126 132 147 166 190 196 204 212 220 229 238

TGK-10


DCF

12m target price


Valuation


EBIT 55 224 414 488 665 763 889 915 951 989 1 028 1 069 1 111

Tax on EBIT - 13 - 54 - 99 - 117 - 160 - 183 - 213 - 220 - 228 - 237 - 247 - 256 - 267

After tax EBIT 42 170 315 371 505 580 676 696 723 751 781 812 845

Depreciation 74 106 125 131 146 156 163 169 176 183 191 198 206

Capex - 698 - 854 - 659 - 566 - 349 - 157 - 162 - 167 - 174 - 181 - 188 - 196 - 204

Change in WC 5 - 15 - 1 26 - 29 - 20 - 7 - 6 - 8 - 8 - 9 - 9 - 9

FCFF - 578 - 593 - 220 - 39 273 559 669 692 717 745 775 805 837

Discounted FCFF - 545 - 502 - 167 - 26 167 307 329 306 284 265 247 231 215

WACC 11.4%




Fair EV 3 439

Net debt 2007e (adj. for SPO in 2008) 1 816


Fair MCap 5 155


Upside to FV 27%

12m TP, USD 6.65

Upside to TP 44%

Dividend yield 0.1%



Shares outstanding, mn 879

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.4% 7.81 8.29 8.90 9.70 10.79

10.4% 6.85 7.20 7.63 8.18 8.90

11.4% 6.08 6.34 6.65 7.04 7.53

12.4% 5.44 5.64 5.87 6.16 6.51

13.4% 4.92 5.07 5.25 5.46 5.71

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

9.4% 1 486 1 613 1 775 1 986 2 276

10.4% 1 231 1 324 1 438 1 584 1 774

11.4% 1 026 1 095 1 178 1 281 1 412

12.4% 858 910 972 1 047 1 140

13.4% 718 758 805 861 929

Terminal growth


Chelyabinsk 576 457 1 034 945 58 1 091 998

Tyumen 1 094 358 1 451 864 344 1 796 1 069

Kurgan 88 133 221 460 0 221 460

Khantymansiysk 0 0 0 0 728 728 0

TGK-10 total 1 758 948 2 706 832 1 130 3 835 1 179

Branch


Existing assets New



TGK-11



Gas-fired plants in Siberia

6-month performance

Assets



2007e 2011e 2007e 2008e

-40%

-30%

-20%

-10%

0%

10%

20%


Branch Region

Installed

electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Tomskenergo Tomsk 421 2 371 1 959 3 530

Omsk GC Omsk 1 605 5 831 6 137 10 185

TGK-11 total 2 026 8 202 8 096 13 715

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Tomskenergo replacement of old capacity 2008 50 105 gas 54 1

Omsk GCnew 285 MW turbine, reconstruction with

2x60 CCGT, 3x30 MW turbines2016 495 702 gas 556 - 143

Gas51.0%

Coal48.2%

Fuel oil

0.8%

Gas44.2%

Coal55.1%

Fuel oil

0.7%

UES50.5%

SUEK26.4%

Rosnef t5.3%

Other minorities

17.8%

E428.9%

SUEK26.4%

Gazprom5.3%

Rosneft5.3%

Other minorities

34.1%

TGK-11


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 482 540 654 817 988 1 126 1 148 1 177 1 195 1 212 1 229 1 246 1 262 1 279 1 296

Non-cash WC 0 4 11 19 27 38 51 61 68 71 75 79 83 88 92

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 407 471 542 578 607 648 776 983 1 260 1 547 1 845 2 156 2 480 2 818 3 170


Net debt (+) or cash (-) 14 9 57 195 345 455 362 195 - 57 - 323 - 601 - 891 -1 194 -1 511 -1 842


Income statement*

Revenues 439 502 639 711 749 856 1 142 1 364 1 523 1 598 1 690 1 778 1 871 1 968 2 072

Electricity 178 210 249 286 302 375 589 728 845 883 931 983 1 037 1 095 1 156

Heat 235 261 356 389 409 442 512 594 633 669 712 746 782 820 860

Other 26 30 34 36 38 39 40 42 44 46 48 49 51 54 56

Cost of sales - 414 - 459 - 562 - 634 - 696 - 789 - 956 -1 090 -1 157 -1 219 -1 296 -1 367 -1 442 -1 522 -1 606

Fuel costs - 180 - 203 - 282 - 325 - 360 - 421 - 548 - 655 - 691 - 726 - 775 - 817 - 861 - 907 - 956

D&A - 28 - 30 - 35 - 41 - 46 - 50 - 55 - 59 - 63 - 66 - 69 - 73 - 76 - 80 - 84

Fixed costs - 206 - 225 - 246 - 269 - 290 - 317 - 353 - 376 - 403 - 427 - 451 - 478 - 505 - 535 - 566

EBITDA 55 75 114 120 102 121 244 336 431 448 467 487 508 530 553

EBIT 27 44 79 79 56 70 188 276 369 382 398 414 432 450 469

EBT 24 43 78 78 54 69 187 275 367 381 396 413 431 449 468

Net income 18 33 59 59 41 53 142 209 279 289 301 314 327 341 356

EBITDA margin 12% 15% 18% 17% 14% 14% 21% 25% 28% 28% 28% 27% 27% 27% 27%

EBIT margin 6% 9% 12% 11% 7% 8% 16% 20% 24% 24% 24% 23% 23% 23% 23%

Net margin 4% 7% 9% 8% 6% 6% 12% 15% 18% 18% 18% 18% 17% 17% 17%

Cash flow statement

Change in WC - 10 - 5 - 7 - 8 - 8 - 12 - 14 - 10 - 7 - 3 - 4 - 4 - 4 - 4 - 5

OCF 41 60 88 93 81 92 185 260 336 353 368 384 401 418 436

Net capex - 31 - 53 - 135 - 234 - 235 - 209 - 99 - 89 - 80 - 83 - 86 - 90 - 93 - 97 - 101


ICF - 29 - 53 - 135 - 234 - 235 - 209 - 99 - 89 - 80 - 83 - 86 - 90 - 93 - 97 - 101


Change in debt - 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 8 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1

Net CF 4 5 - 48 - 142 - 156 - 118 85 169 254 269 280 293 306 320 334


2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.2 0.9 0.8 0.8 0.7 0.5 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.3

EV/EBITDA 7.8 5.1 4.9 5.7 4.8 2.4 1.7 1.4 1.3 1.2 1.2 1.1 1.1 1.1

P/E 17.5 9.7 9.7 13.9 10.9 4.0 2.7 2.1 2.0 1.9 1.8 1.8 1.7 1.6

2006 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 21% 19% 22% 22% 22% 22% 23% 23% 23% 23% 23% 24% 24% 24% 24%


USD/MWh25 30 35 38 41 47 59 74 83 87 90 94 97 100 104

Fuel cost, USD/MWh 25 29 40 43 48 53 55 66 68 71 75 78 80 83 86

EBITDA/kW, USD 27 37 56 58 49 55 97 132 168 174 182 189 198 206 215

TGK-11


DCF

12m target price


Valuation


EBIT 79 79 56 70 188 276 369 382 398 414 432 450 469

Tax on EBIT - 19 - 19 - 13 - 17 - 45 - 66 - 89 - 92 - 95 - 99 - 104 - 108 - 113

After tax EBIT 60 60 42 54 143 210 280 290 302 315 328 342 357

Depreciation 35 41 46 50 55 59 63 66 69 73 76 80 84

Capex - 135 - 234 - 235 - 209 - 99 - 89 - 80 - 83 - 86 - 90 - 93 - 97 - 101

Change in WC - 7 - 8 - 8 - 12 - 14 - 10 - 7 - 3 - 4 - 4 - 4 - 4 - 5

FCFF - 47 - 141 - 155 - 117 86 170 255 270 281 294 307 321 335

Discounted FCFF - 44 - 116 - 111 - 74 48 83 109 101 93 85 78 71 65

WACC 13.9%




Fair EV 951

Net debt 2007e - 9

Minority interest 0

Fair MCap 943


Upside to FV 64%

12m TP, USD 0.00215

Upside to TP 92%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

11.9% 0.00268 0.00284 0.00303 0.00327 0.00357

12.9% 0.00228 0.00240 0.00255 0.00272 0.00293

13.9% 0.00194 0.00204 0.00215 0.00228 0.00244

14.9% 0.00166 0.00174 0.00182 0.00192 0.00204

15.9% 0.00142 0.00148 0.00155 0.00163 0.00172

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

11.9% 666 705 753 812 885

12.9% 566 597 633 676 729

13.9% 484 507 535 567 606

14.9% 415 433 454 479 508

15.9% 356 370 387 406 429

Terminal growth


Tomskenergo 126 235 362 859 1 362 860

Omsk GC 410 475 885 552 - 163 722 450

TGK-11 total 536 711 1 247 615 - 162 1 084 535

Branch


Existing assets New



Kuzbassenergo (TGK-12)




6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Kuzbassenergo RTS Index RTS Electric Utilities Index

Branch Region

Installed

electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Kuzbass Kemerovo 3 603 5 339 20 029 9 350

Barnaul Altai 784 3 503 3 202 5 280

Kuzbassenergo total 4 387 8 842 23 232 14 630

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Kuzbass Reconstruction and expansion 2011 1 112 0 coal 1 608 - 10

Gas5.8%

Coal92.4%

Fuel oil

1.7%

Fuel mix, 2007e

Gas5.0%

Coal93.6%

Fuel oil

1.4%

Fuel mix, 2011e

UES49%

SUEK45%

Other minorities

6%


SUEK55%

Other minorities

41%

Gazprom4%




Financials

Financial ratios

Operational data



Non-cash WC 9 65 22 32 43 67 78 91 103 108 113 120 127 134 141

LT investments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Equity 521 1 245 1 261 1 224 1 236 1 394 1 678 2 148 2 761 3 394 4 049 4 734 5 449 6 194 6 958


Net debt (+) or cash (-) 40 - 223 - 28 544 1 079 1 189 858 387 - 229 - 873 -1 540 -2 234 -2 958 -3 711 -4 486

Other LT liabilities (+) or assets (-) - 100 138 141 135 133 130 128 128 128 128 128 128 128 128 128

Income statement*Revenues 697 754 873 1 014 1 131 1 500 1 744 2 031 2 306 2 420 2 546 2 694 2 852 3 013 3 156

Electricity 497 465 516 633 734 1 085 1 301 1 548 1 794 1 878 1 974 2 092 2 218 2 344 2 448

Heat 159 249 311 332 346 363 389 426 452 480 508 536 565 597 632

Other 41 41 46 49 51 52 54 57 59 62 64 67 70 72 75

Cost of sales - 658 - 741 - 889 - 996 -1 082 -1 259 -1 331 -1 406 -1 491 -1 580 -1 675 -1 785 -1 902 -2 024 -2 140

Fuel costs - 296 - 382 - 492 - 548 - 578 - 663 - 708 - 751 - 798 - 850 - 908 - 977 -1 051 -1 128 -1 197

D&A - 57 - 63 - 74 - 97 - 127 - 157 - 166 - 172 - 179 - 186 - 192 - 200 - 207 - 215 - 223

Fixed costs - 305 - 296 - 324 - 351 - 377 - 439 - 457 - 482 - 514 - 544 - 575 - 609 - 644 - 681 - 721

EBITDA 96 76 58 115 176 399 579 797 994 1 026 1 063 1 109 1 157 1 204 1 239

EBIT 39 13 - 15 18 48 241 413 624 815 840 871 909 950 989 1 016

EBT 39 8 - 16 18 48 241 413 624 815 840 870 909 950 989 1 016

Net income 79 6 - 16 14 37 183 314 474 619 639 662 691 722 752 772

EBITDA margin 14% 10% 7% 11% 16% 27% 33% 39% 43% 42% 42% 41% 41% 40% 39%

EBIT margin 6% 2% neg 2% 4% 16% 24% 31% 35% 35% 34% 34% 33% 33% 32%

Net margin 11% 1% neg 1% 3% 12% 18% 23% 27% 26% 26% 26% 25% 25% 24%


Cash flow statementChange in WC - 21 - 67 44 - 10 - 12 - 25 - 12 - 13 - 12 - 5 - 6 - 7 - 7 - 7 - 6

OCF 62 - 29 105 100 152 316 468 634 786 819 849 884 922 960 989

Net capex - 46 - 273 - 304 - 682 - 702 - 448 - 156 - 158 - 164 - 169 - 176 - 183 - 191 - 199 - 206

Acquisitions/divestments - 3 266 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 53 - 6 - 304 - 682 - 702 - 448 - 156 - 158 - 164 - 169 - 176 - 183 - 191 - 199 - 206


Change in debt 5 - 49 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 21 238 0 0 0 0 0 0 0 0 0 0 0 0 0

Net CF - 11 203 - 198 - 583 - 551 - 132 311 476 622 650 673 701 731 760 783

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.9 1.6 1.4 1.3 1.0 0.8 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5

EV/EBITDA 18.8 24.6 12.5 8.2 3.6 2.5 1.8 1.4 1.4 1.3 1.3 1.2 1.2 1.2

P/E 265.8 neg 122.2 45.1 9.0 5.3 3.5 2.7 2.6 2.5 2.4 2.3 2.2 2.1

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 19% 19% 19% 19% 19% 20% 20% 20% 20% 20% 21% 21% 21% 21% 21%


USD/MWh20 22 24 30 35 45 54 66 76 80 83 86 89 92 96

Fuel cost, USD/MWh 12 18 23 26 28 27 29 32 34 36 38 40 42 44 47

EBITDA/kW, USD 17 17 13 26 40 78 113 155 194 200 207 216 226 235 241



DCF

12m target price


Valuation


EBIT - 15 18 48 241 413 624 815 840 871 909 950 989 1 016

Tax on EBIT 4 - 4 - 12 - 58 - 99 - 150 - 196 - 202 - 209 - 218 - 228 - 237 - 244

After tax EBIT - 12 14 37 183 314 474 619 639 662 691 722 752 772

Depreciation 74 97 127 157 166 172 179 186 192 200 207 215 223

Capex - 304 - 682 - 702 - 448 - 156 - 158 - 164 - 169 - 176 - 183 - 191 - 199 - 206

Change in WC 44 - 10 - 12 - 25 - 12 - 13 - 12 - 5 - 6 - 7 - 7 - 7 - 6

FCFF - 198 - 583 - 551 - 132 312 476 622 650 673 701 731 760 783

Discounted FCFF - 186 - 488 - 412 - 88 185 252 294 274 253 235 218 203 186

WACC 12.1%




Fair EV 2 799

Net debt 2007 223

Minority interest 0

Fair MCap 3 022


Upside to FV 83%

12m TP, USD 0.0490

Upside to TP 109%

Dividend yield 0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 0.0608 0.0653 0.0709 0.0781 0.0876

11.1% 0.0513 0.0546 0.0586 0.0637 0.0701

12.1% 0.0435 0.0460 0.0490 0.0526 0.0572

13.1% 0.0370 0.0390 0.0412 0.0439 0.0472

14.1% 0.0317 0.0332 0.0349 0.0369 0.0394

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 903 973 1 062 1 175 1 325

11.1% 752 804 868 947 1 049

12.1% 629 668 715 773 845

13.1% 527 557 593 636 688

14.1% 443 466 493 525 564

Terminal growth


Kuzbass 2 028 476 2 504 695 - 12 2 493 692

Barnaul 236 412 648 827 0 648 827

Kuzbassenergo total 2 265 888 3 153 719 - 12 3 141 716

Plant


Existing assets New



TGK-13

Strengths Below-average effective fuel price



Risks related to lawsuit from Rosneft

6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Krasnoyarsk Krasnoyarsk 2 205 6 920 10 452 11 834

Khakassia Khakassia 270 481 1 078 1 251

TGK-13 total 2 475 7 401 11 530 13 085

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Krasnoyarsk2 new 185 MW and 30 MW turbines,

reconstruction of existing capacity2010 442 540 coal 625 125

Coal98.9%

Fuel oil

1.1%

Coal99.1%

Fuel oil

0.9%

UES57%

SUEK35%

Other minorities

8%

SUEK47%

Gazprom5%

Other minorities

26%

KIT Finance4%

Metropol3%

Donalink Ltd.15%

TGK-13


Financials

Financial ratios

Operational data


Balance sheet

Fixed assets 1 127 1 192 1 391 1 509 1 661 1 702 1 676 1 680 1 683 1 686 1 688 1 691 1 693 1 697 1 700

Non-cash WC 9 16 17 22 27 35 41 48 55 58 61 64 68 72 76

LT investments 74 83 91 127 208 343 436 555 693 847 1 018 1 208 1 419 1 653 1 913

Equity 1 004 1 030 1 277 1 259 1 312 1 478 1 687 2 033 2 476 2 940 3 427 3 942 4 486 5 065 5 682


Net debt (+) or cash (-) 34 93 49 234 422 444 310 94 - 200 - 505 - 816 -1 135 -1 462 -1 799 -2 148


Income statement*

Revenues 319 401 480 600 650 792 925 1 086 1 244 1 304 1 369 1 443 1 522 1 610 1 704

Electricity 102 162 198 301 350 480 597 732 866 903 945 998 1 053 1 116 1 183

Heat 199 219 259 275 274 286 302 326 348 370 391 412 434 458 483

Other 17 20 23 25 25 26 27 28 30 31 32 33 35 36 38

Cost of sales - 378 - 455 - 523 - 593 - 629 - 678 - 709 - 746 - 795 - 844 - 895 - 952 -1 014 -1 079 -1 149

Fuel costs - 119 - 146 - 190 - 228 - 243 - 269 - 283 - 297 - 319 - 341 - 365 - 394 - 425 - 458 - 493

D&A - 71 - 76 - 83 - 90 - 93 - 85 - 89 - 92 - 96 - 100 - 105 - 109 - 114 - 118 - 123

Fixed costs - 188 - 232 - 249 - 276 - 294 - 324 - 337 - 356 - 380 - 402 - 425 - 450 - 476 - 503 - 532

EBITDA 17 30 48 104 122 207 314 442 555 571 589 611 633 661 690

EBIT - 54 - 47 - 35 14 29 122 225 349 458 470 484 501 520 543 567

EBT - 52 - 48 - 40 45 103 253 315 460 588 616 647 683 723 769 820

Net income - 52 - 48 - 40 34 78 193 240 350 447 468 492 519 549 585 623

EBITDA margin 5% 7% 10% 17% 19% 26% 34% 41% 45% 44% 43% 42% 42% 41% 40%



Cash flow statement

Change in WC - 3 - 10 0 - 6 - 5 - 9 - 7 - 7 - 7 - 3 - 3 - 3 - 4 - 4 - 4

OCF 9 19 57 87 92 137 231 324 407 420 431 443 456 472 489

Net capex - 29 - 64 - 253 - 268 - 276 - 158 - 95 - 96 - 100 - 103 - 107 - 112 - 117 - 122 - 127


ICF - 29 - 63 - 253 - 268 - 276 - 158 - 95 - 96 - 100 - 103 - 107 - 112 - 117 - 122 - 127


Change in debt 29 57 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 24 48 241 - 10 - 10 - 10 - 10 - 10 - 10 - 10 - 10 - 10 - 10 - 10 - 10

Net CF 4 3 45 - 191 - 194 - 31 127 218 297 308 314 322 330 341 352


2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 2.9 2.4 1.9 1.8 1.5 1.3 1.1 0.9 0.9 0.8 0.8 0.8 0.7 0.7

EV/EBITDA 39.1 24.1 11.1 9.5 5.6 3.7 2.6 2.1 2.0 2.0 1.9 1.8 1.8 1.7

P/E neg neg 38.8 16.8 6.8 5.5 3.8 2.9 2.8 2.7 2.5 2.4 2.2 2.1

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e






Load factor (heat) 22% 20% 20% 21% 21% 21% 21% 22% 22% 22% 22% 22% 23% 23% 23%


USD/MWh11 16 19 25 30 38 48 61 71 74 76 79 81 84 87

Fuel cost, USD/MWh 13 14 18 19 21 21 23 25 26 28 30 31 33 34 36

EBITDA/kW, USD 7 12 19 38 44 70 106 148 186 192 198 205 213 222 232

TGK-13


DCF

12m target price


Valuation


EBIT - 35 14 29 122 225 349 458 470 484 501 520 543 567

Tax on EBIT 8 - 3 - 7 - 29 - 54 - 84 - 110 - 113 - 116 - 120 - 125 - 130 - 136

After tax EBIT - 27 11 22 93 171 265 348 357 368 381 395 412 431

Depreciation 83 90 93 85 89 92 96 100 105 109 114 118 123

Capex - 253 - 268 - 276 - 158 - 95 - 96 - 100 - 103 - 107 - 112 - 117 - 122 - 127

Change in WC 0 - 6 - 5 - 9 - 7 - 7 - 7 - 3 - 3 - 3 - 4 - 4 - 4

FCFF - 197 - 173 - 166 11 158 254 338 352 363 375 388 405 423

Discounted FCFF - 185 - 145 - 124 7 94 135 160 148 136 126 116 108 100

WACC 12.1%


NPV of cash flows 676


Fair EV 1 687

Net debt 2007 (adj. for SPO in 2008) 156

25% stake in Kransoyarsk GES at

target value 909

Fair MCap 2 753


Upside to FV 110%

12m TP, USD 0.0198

Upside to TP 140%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 0.0227 0.0238 0.0251 0.0268 0.0291

11.1% 0.0204 0.0212 0.0221 0.0233 0.0249

12.1% 0.0185 0.0191 0.0198 0.0207 0.0218

13.1% 0.0169 0.0174 0.0179 0.0185 0.0193

14.1% 0.0156 0.0159 0.0163 0.0168 0.0174

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.1% 948 1 016 1 100 1 208 1 352

11.1% 801 851 912 989 1 086

12.1% 681 719 764 819 888

13.1% 582 611 645 686 736

14.1% 499 522 548 579 615

Terminal growth


Krasnoyarsk 1 007 550 1 557 706 140 1 698 770

Khakassia 137 58 195 724 0 195 724

TGK-13 total 1 144 609 1 753 708 140 1 893 765

Branch

12m Target EV, USD mn

Existing assets New



TGK-14




6-month performance

Assets



2007e 2011e 2007e 2008e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%


Branch Region

Installed

electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation

2007,

GWh

Heat sales

2007,

k GCal

Buryatia Buryatia 130 744 366 1 270

Chita Chita 513 1 533 2 000 2 696

TGK-14 total 643 2 277 2 365 3 966

Branch Project

Completion

date

New

electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial

investment

outlay,

USD mn

NPV,

USD mn

Buryatia 2 new 20 MW turbines 2010 40 0 coal 56 - 25

Chita new 6 MW turbine 2008 6 34 coal 8 1

Coal99.8%

Fuel oil

0.2%

Coal99.7%

Fuel oil

0.3%

State50%

Norilsk Nickel28%

Other minorities

22%

Norilsk Nickel28%

Other minorities

22%

Energopromsbyt(51% owned by

Russian

Railways)50%

TGK-14


Financials

Financial ratios

Operational data

USD mn 2006 2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Balance sheet

Fixed assets 148 166 211 235 236 238 240 246 252 258 263 269 274 280 286

Non-cash WC 5 5 6 7 9 10 11 13 14 15 16 17 18 19 21

LT investments 5 5 6 5 5 5 5 5 5 5 5 5 5 5 5

Equity 165 185 208 218 231 245 273 323 388 455 525 598 674 754 837


Net debt (+) or cash (-) - 7 - 8 16 30 19 8 - 16 - 59 - 116 - 177 - 241 - 307 - 376 - 449 - 525


Income statement*

Revenues 173 150 180 200 214 225 253 288 324 343 362 385 408 434 461

Electricity 62 59 60 75 85 91 112 137 162 170 180 191 204 217 231

Heat 101 80 106 112 115 119 126 136 146 155 165 175 185 197 209

Other 10 11 13 14 14 15 15 16 17 17 18 19 19 20 21

Cost of sales - 155 - 140 - 154 - 175 - 190 - 200 - 210 - 222 - 237 - 253 - 269 - 287 - 306 - 327 - 349

Fuel costs - 73 - 64 - 77 - 90 - 98 - 103 - 109 - 115 - 124 - 133 - 142 - 153 - 165 - 177 - 191

D&A - 9 - 9 - 11 - 12 - 12 - 12 - 12 - 13 - 14 - 15 - 15 - 16 - 17 - 18 - 19

Fixed costs - 73 - 67 - 67 - 73 - 79 - 85 - 88 - 93 - 99 - 105 - 111 - 118 - 124 - 132 - 139

EBITDA 27 19 36 38 36 37 56 80 101 105 109 114 119 125 130

EBIT 18 10 26 26 24 25 44 67 87 90 93 98 102 106 111

EBT 17 10 25 25 23 24 43 66 86 89 93 97 101 106 110

Net income 13 7 19 19 18 19 33 50 66 68 71 74 77 80 84

EBITDA margin 16% 13% 20% 19% 17% 16% 22% 28% 31% 31% 30% 30% 29% 29% 28%

EBIT margin 11% 7% 14% 13% 11% 11% 17% 23% 27% 26% 26% 25% 25% 25% 24%

Net margin 8% 5% 10% 9% 8% 8% 13% 17% 20% 20% 19% 19% 19% 19% 18%

Cash flow statement

Change in WC - 4 0 - 1 - 1 - 1 - 1 - 1 - 2 - 2 - 1 - 1 - 1 - 1 - 1 - 1

OCF 17 18 29 30 29 30 44 62 79 82 86 90 94 98 103

Net capex - 2 - 17 - 52 - 45 - 18 - 18 - 19 - 19 - 20 - 20 - 21 - 22 - 23 - 24 - 25


ICF - 9 - 16 - 51 - 45 - 17 - 18 - 18 - 19 - 19 - 20 - 21 - 22 - 22 - 23 - 24


Change in debt 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1 - 1

Net CF 8 0 - 23 - 16 11 11 25 43 58 61 64 67 70 73 77


2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 1.6 1.4 1.2 1.1 1.1 1.0 0.8 0.8 0.7 0.7 0.6 0.6 0.6 0.5

EV/EBITDA 12.6 6.8 6.5 6.7 6.6 4.4 3.1 2.4 2.3 2.2 2.1 2.1 2.0 1.9

P/E 34.6 13.4 13.4 14.2 13.7 7.7 5.0 3.8 3.7 3.6 3.4 3.3 3.1 3.0

2006 2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Electric capacity, MW 643 643 519 539 559 559 559 559 559 559 559 559 559 559 559





Load factor (heat) 20% 20% 20% 20% 21% 21% 21% 21% 21% 22% 22% 22% 22% 22% 23%


USD/MWh26 29 33 37 41 46 57 72 84 88 91 95 99 102 106

Fuel cost, USD/MWh 31 32 42 45 48 52 55 61 65 69 72 76 80 84 88

EBITDA/kW, USD 42 30 70 70 65 66 100 143 181 187 195 204 213 223 233

TGK-14


DCF

12m target price


Valuation

USD mn 2007e 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EBIT 10 26 26 24 25 44 67 87 90 93 98 102 106 111

Tax on EBIT - 2 - 6 - 6 - 6 - 6 - 10 - 16 - 21 - 22 - 22 - 23 - 24 - 26 - 27

After tax EBIT 8 19 19 18 19 33 51 66 68 71 74 77 81 84

Depreciation 9 11 12 12 12 12 13 14 15 15 16 17 18 19

Capex - 17 - 52 - 45 - 18 - 18 - 19 - 19 - 20 - 20 - 21 - 22 - 23 - 24 - 25

Change in WC 0 - 1 - 1 - 1 - 1 - 1 - 2 - 2 - 1 - 1 - 1 - 1 - 1 - 1

FCFF 1 - 23 - 15 11 11 25 43 59 62 65 67 71 74 77

Discounted FCFF 1 - 21 - 13 8 7 15 22 27 25 23 21 20 18 17

WACC 12.8%




Fair EV 330

Net debt 2007e 8

Minority interest 0

Fair MCap 338


Upside to FV 34%

12m TP, USD 0.000501

Upside to TP 54%

Dividend yield 0.0%




WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 0.000601 0.000634 0.000674 0.000725 0.000790

11.8% 0.000524 0.000548 0.000578 0.000614 0.000660

12.8% 0.000460 0.000478 0.000501 0.000527 0.000560

13.8% 0.000406 0.000421 0.000438 0.000458 0.000482

14.8% 0.000361 0.000372 0.000385 0.000401 0.000419

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.8% 696 735 783 843 920

11.8% 605 634 669 712 766

12.8% 530 552 578 610 648

13.8% 466 483 503 527 556

14.8% 413 426 442 460 481

Terminal growth


Buryatia 0 105 105 806 - 28 77 588

Chita 160 135 295 574 1 296 576

TGK-14 total 160 240 400 621 - 28 372 578

Plant


Existing assets New



Bashkirenergo



Weaknesses Poor corporate governance

6-month performance

Assets



2007e 2011e 2007e 2008e

Operational data

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Bashkirenergo common RTS Index


Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Bashkirenergo Thermal Bashkiria 4 933 17 349 24 506 31 657

Bashkirenergo Hydro Bashkiria 213 0 908 0

Bashkirenergo total 5 147 17 349 25 414 31 657

Branch Project

Completion

date

New electric

capacity,

MW

New heat

capacity,

Gcal/h

Fuel

type

Initial investment

outlay,

USD mn

NPV,

USD mn

Bashkirenergo Thermal new 450 MW CCGT 2012 450 0 gas 500 98

Gas92.5%

Coal1.4%

Fuel oil6.1%

Fuel mix, 2007e

Gas92.7%

Coal1.4%

Fuel oil5.9%

Fuel mix, 2011e

UES21%

Bashnef t12%

Novo-Ufa Oil Ref inery

12% Ufanef tekhim13%

Ufa Oil Ref inery

12%

Other minorities

30%


Bashnef t12%

Novo-Ufa Oil Ref inery

12%

Ufanef tekhim13%

Ufa Oil Ref inery

12%

Unitrade21%

Other minorities

30%








Load factor (heat) 22% 21% 21% 21% 21% 22% 22% 22% 22% 23% 23% 23% 23% 23% 24%

Bashkirenergo


DCF, generation assets

Sum-of-parts valuation

12m target price


Valuation, generation assets


USD mn 2 008 2 009 2 010 2 011 2 012 2 013 2 014 2 015 2 016 2 017 2 018 2 019 2 020

EBIT - 11 101 185 207 367 474 639 659 691 725 760 797 837

Tax on EBIT 3 - 24 - 44 - 50 - 105 - 137 - 182 - 187 - 194 - 201 - 208 - 216 - 224

After tax EBIT - 8 77 141 158 262 337 457 472 497 524 552 581 613

Depreciation 60 84 108 135 141 148 153 159 165 171 178 185 192

Capex - 218 - 224 - 229 - 233 - 187 - 138 - 142 - 147 - 154 - 160 - 168 - 175 - 183

Change in WC - 4 - 7 2 13 - 21 - 19 - 9 - 6 - 8 - 8 - 8 - 9 - 9

FCFF - 171 - 71 22 72 195 328 458 479 501 526 553 582 612

WACC 12.6%


NPV of cash flow 1 331 50%

NPV of terminal value 1 329 50%

Fair EV 2 660

Excl.

investment

projects

Incl.

investment

projects

Fair EV of generation, USD mn 2 561 2 660

Fair EV of grids, USD mn 1 133 1 133

Total Fair EV, USD mn 3 695 3 793

Net debt 2007e, USD mn - 49 - 49

Fair MCap, USD mn 3 645 3 744

Common shares outstanding, mn 1 043 1 043


FV of common share, USD 3.43 3.52

12m TP of common share, USD 3.94 4.04

Current common share price, USD 1.59 1.59

Upside to TP, common share 148% 155%

FV of preferred share, USD 1.46 1.50

12m TP of preferred share, USD 1.68 1.72

Current preferred share price, USD 1.56 1.56

Upside to TP, preferred share 8% 11%

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.6% 4.64 4.84 5.09 5.40 5.82

11.6% 4.17 4.32 4.51 4.73 5.02

12.6% 3.79 3.91 4.04 4.21 4.41

13.6% 3.47 3.56 3.67 3.79 3.94

14.6% 3.20 3.27 3.35 3.45 3.56

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.6% 950 991 1 042 1 106 1 189

11.6% 856 887 924 970 1 027

12.6% 779 802 830 863 904

13.6% 714 732 753 778 809

14.6% 660 674 690 709 732

Terminal growth


Bashkirenergo Thermal 1 678 1 009 2 687 545 111 2 798 567

Bashkirenergo Hydro 199 0 199 932 0 199 932

Bashkirenergo total 1 876 1 009 2 886 561 111 2 996 582

Plant


Existing assets New



Irkutskenergo

Strengths Hydro power plants


Effective fuel price Below-average


Weaknesses Poor corporate governance, transfer

pricing risks

6-month performance

Assets



2007e 2011e 2007e 2008e

Operational data

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Irkutskenergo

RTS Index


Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Irkutskenergo Thermal Irkutsk 3 878 13 002 10 840 23 985

Irkutskenergo Hydro Irkutsk 9 002 0 47 625 0

Irkutskenergo total 12 880 13 002 58 465 23 985

Branch Project

Completion

date

New electric

capacity,

MW

New heat

capacity,

Gcal/h Fuel type

Initial investment

outlay,

USD mn

NPV,

USD mn

Irkutskenergo Thermal new turbine 2015 300 gas 353 - 105

Irkutskenergo Thermal new power plant & new unit 2016 1 320 coal 2 081 - 204

Coal99.5%

Fuel oil

0.5%

Fuel mix, 2007e

Coal99.5%

Fuel oil

0.5%

Fuel mix, 2011e

Russian Federation

40%Nominal holders

47%

Other minorities

13%


Russian Federation

40% Nominal holders

47%

Other minorities

13%







Heat sales, Gcal th 24 590 23 985 24 225 24 467 24 712 24 959 25 209 25 461 25 716 25 973 26 232 26 495 26 760 27 027 27 298

Load factor (heat) 22% 21% 21% 21% 22% 22% 22% 22% 23% 23% 23% 23% 23% 24% 24%

Irkutskenergo




12m target price




EBIT 184 543 840 1 288 1 925 2 812 3 607 3 807 4 014 4 148 4 287 4 432 4 581

Tax on EBIT - 44 - 130 - 202 - 309 -1 151 -1 768 -2 300 -2 329 -2 348 -2 341 -2 324 -2 297 -2 257

After tax EBIT 140 412 639 979 774 1 044 1 307 1 479 1 665 1 807 1 963 2 135 2 324

Depreciation 185 173 158 144 174 211 244 271 290 307 324 341 360

Capex - 278 - 315 - 513 - 722 - 915 - 923 - 751 - 568 - 405 - 419 - 433 - 448 - 463

Change in WC - 15 - 21 - 35 - 55 - 34 - 47 - 44 - 17 - 16 - 11 - 11 - 12 - 12

FCFF 31 250 249 347 - 2 285 756 1 164 1 534 1 684 1 843 2 017 2 209

Discounted FCFF 29 205 180 220 - 1 140 327 443 514 496 478 460 443

WACC 13.6%




Fair EV 7 822

Excl.

investment

projects

Inlc.

investment

projects

Fair EV of generation, USD mn 8 131 7 822

Fair EV of grids, USD mn 975 975

Total fair EV, USD mn 9 106 8 797

Total 12m Target EV, USD mn 10 352 10 001

Net debt 2007e, USD mn - 23 - 23

Fair MCap, USD mn 9 084 8 774

Common shares outstanding, mn 4 767 4 767

FV of common share, USD 1.91 1.84

12m TP, USD 2.21 2.14



WACC

11.6% 2.51 2.63 2.78 2.96 3.19

12.6% 2.23 2.32 2.43 2.56 2.72

13.6% 1.99 2.06 2.14 2.24 2.36

14.6% 1.79 1.84 1.91 1.98 2.07

15.6% 1.62 1.67 1.72 1.77 1.84

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

11.6% 910 954 1 007 1 072 1 155

12.6% 806 839 879 927 986

13.6% 720 746 776 812 855

14.6% 648 669 692 719 752

15.6% 588 604 622 643 668

Terminal growth


Irkutskenergo Thermal 1 470 786 2 256 582 - 351 1 905 491

Irkutskenergo Hydro 6 988 0 6 988 776 0 6 988 776

Irkutskenergo total 8 458 786 9 244 718 - 351 8 893 690

Plant


Existing assets New



Novosibirskenergo

Strengths Below-average fuel burn rate


Poor corporate governance

6-month performance

Assets


2007e 2011e 2007e 2008e

Operational data

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

Novosibirskenergo common

RTS Index


Gas7.5%

Coal92.0%

Fuel oil0.5%

Fuel mix, 2007e

Gas7.5%

Coal92.0%

Fuel oil0.5%

Fuel mix, 2011e

UES14%

Power Measurement

25%Ferncote Ltd

11%

Romos Ltd11%

IK Gazinvest

AM

7%Troika Dialog

AM

7%

UFG IS

Trading

Ltd7%

Other24%


Renaissance Capital14%

Power Measurement

25%Ferncote Ltd

11%

Romos Ltd11%

IK Gazinvest

AM

7%Troika Dialog

AM

7%

UFGIS

Trading

Ltd7%

Other24%







Heat sales, Gcal th 13 041 13 171 13 303 13 436 13 571 13 706 13 843 13 982 14 122 14 263 14 405 14 549 14 695 14 842 14 990

Load factor (heat) 21% 21% 21% 21% 21% 22% 22% 22% 22% 22% 23% 23% 23% 23% 24%

Branch Region

Installed electric

capacity 2007,

MW

Installed heat

capacity 2007,

Gcal/h

Electricity

generation 2007,

GWh

Heat sales

2007,

k GCal

Novosibirskenergo Novosibirsk 2 522 7 246 10 304 13 171

Novosibirskenergo








EBIT 45 42 41 64 156 273 372 383 396 411 427 444 462

Tax on EBIT - 11 - 10 - 10 - 15 - 38 - 65 - 89 - 92 - 95 - 99 - 103 - 107 - 111

After tax EBIT 34 32 31 49 119 207 283 291 301 313 325 338 351

Depreciation 83 74 62 50 52 55 58 61 64 68 71 75 79

Capex - 66 - 69 - 70 - 71 - 73 - 73 - 76 - 79 - 82 - 85 - 89 - 93 - 98

Change in WC 13 27 31 35 - 7 - 7 - 7 - 3 - 3 - 4 - 4 - 4 - 4

FCFF 64 64 54 63 92 182 258 271 280 291 303 315 327

Discounted FCFF 60 53 40 42 53 94 119 111 102 94 87 80 74

WACC 12.6%




Fair EV 1 719

Fair EV of generation, USD mn 1 719

Fair EV of grids, USD mn 572

Total fair EV, USD mn 2 291

Net debt 2007e, USD mn - 223

Fair Mcap, USD mn 2 068

Common shares outstanding, mn 14

Preferred shares outstanding, mn 3


FV of preferred share, USD 78.1

12m TP of common share, USD 158.8

12m TP of preferred share, USD 89.7

Current common share price, USD 70.5

Current preferred share price, USD 46.0

Upside to TP, common share 125%

Upside to TP, preferred share 95%

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.6% 182.1 189.9 199.4 211.4 227.1

12.6% 149.3 153.6 158.8 165.1 172.9

13.6% 136.8 140.2 144.1 148.8 154.5

14.6% 126.3 128.9 132.0 135.5 139.8

Terminal growth WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.6% 1 158 1 203 1 258 1 328 1 419

11.6% 1 054 1 087 1 128 1 177 1 240

12.6% 967 993 1 023 1 059 1 104

13.6% 895 915 937 965 998

14.6% 834 849 867 887 912


Novosibirskenergo 836 1 097 1 933 767 0 1 933 767

Plant


Existing assets New



RusHydro

Strengths Hydro power plants


Transfer pricing risks

6-month performance

Assets


Ownership structure

2007e 1H08e 2H08e

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Hydro OGK RTS Index RTS Electric Utilities Index

Region Project

Completion

date

New electric

capacity,

MW

Initial investment

outlay,

USD mn

NPV,

USD mn

European Russia Zhigulyevskaya GES, Kamskaya GES,

Sulakenergo, Kaskad Nizhnecherekskih

GES, Gotsatlinskiye GES, Zaramagskiye

GES, Small GES

2010 587 1 124 231

Siberia Boguchanskaya GES 2013 3 000 2 539 92

Isolated Bureyskaya GES 2013 335 994 51

Zagorskaya GAES Zagorskaya GAES-2 2012 840 1 820 7

UES96%

Russian Federation

2%

Option program operator

2%


UES78%

Russian Federation

1%Minorities

21%

Ownership structure, 1H08

Russian Federation

60%

Option program operator

2%

Other minorities

38%

Ownership structure, 2H08e

Region

Installed electric

capacity 2007,

MW

Electricity

generation

2007,

GWh

European Russia 12 600 50 014

Siberia 7 176 22 779

Isolated 3 067 8 976

Zagorskaya GAES 1 200 1 934

RusHydro total 24 043 83 704

RusHydro


Financials

Financial ratios

Operational data

USD mn 2006 2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e


Non-cash WC 415 739 810 742 597 245 299 377 435 451 467 484 501 519 538

LT investments 147 158 162 155 152 149 147 147 147 147 147 147 147 147 147

Equity 3 109 4 976 9 745 10 788 12 686 15 373 17 074 19 415 21 973 24 774 27 840 31 201 34 886 38 930 43 371


Net debt (+) or cash (-) 413 595 -2 208 -2 523 -3 499 -5 787 -7 232 -9 512 -12 035 -14 849 -17 935 -21 323 -25 041 -29 125 -33 613

Other LT liabilities (+)

or assets (-) 228 245 250 240 235 231 226 226 226 226 226 226 226 226 226


Electricity 601 1 443 2 155 2 917 3 980 5 294 6 493 8 220 9 523 9 865 10 216 10 580 10 958 11 350 11 758

Other 144 165 188 200 206 214 220 231 241 251 261 272 283 295 307

Cost of sales - 591 - 762 - 953 -1 131 -1 323 -1 554 -1 668 -1 813 -1 915 -2 014 -2 118 -2 227 -2 342 -2 462 -2 589

D&A - 114 - 163 - 257 - 352 - 446 - 557 - 595 - 626 - 651 - 676 - 703 - 730 - 758 - 786 - 816

Fixed costs - 478 - 599 - 697 - 779 - 877 - 998 -1 074 -1 187 -1 264 -1 338 -1 415 -1 497 -1 584 -1 676 -1 773

EBITDA 267 1 010 1 646 2 338 3 309 4 510 5 640 7 263 8 500 8 778 9 062 9 354 9 657 9 969 10 291

EBIT 153 847 1 390 1 986 2 863 3 953 5 046 6 637 7 849 8 102 8 359 8 625 8 899 9 182 9 475

EBT 141 788 1 327 1 924 2 803 3 894 4 988 6 579 7 792 8 044 8 301 8 567 8 841 9 125 9 417

Net income 87 599 1 009 1 462 2 130 2 960 2 010 2 363 2 583 2 827 3 096 3 393 3 720 4 083 4 483

EBITDA margin 36% 63% 70% 75% 79% 82% 84% 86% 87% 87% 86% 86% 86% 86% 85%

EBIT margin 21% 53% 59% 64% 68% 72% 75% 79% 80% 80% 80% 79% 79% 79% 79%

Net margin 12% 37% 43% 47% 51% 54% 30% 28% 26% 28% 30% 31% 33% 35% 37%


Cash flow statementChange in WC - 542 - 282 - 54 37 132 343 - 59 - 78 - 59 - 16 - 16 - 17 - 18 - 18 - 19

OCF - 343 539 1 274 1 912 2 768 3 918 2 603 2 969 3 232 3 545 3 840 4 163 4 518 4 908 5 337

Net capex - 571 -1 601 -2 022 -1 439 -1 673 -1 481 - 977 - 610 - 628 - 647 - 666 - 686 - 707 - 728 - 750 Acquisitions/

divestments 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 657 -1 599 -2 020 -1 438 -1 671 -1 480 - 976 - 608 - 626 - 645 - 665 - 685 - 705 - 726 - 748

Equity raised/bought

back 736 975 3 594 0 0 0 0 0 0 0 0 0 0 0 0

Change in debt 450 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 1 160 915 3 531 - 63 - 61 - 60 - 59 - 59 - 59 - 59 - 59 - 59 - 59 - 59 - 59

Net CF 160 - 145 2 784 412 1 036 2 378 1 569 2 302 2 547 2 841 3 116 3 419 3 754 4 123 4 530

2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 12.2 8.3 6.3 4.7 3.6 2.9 2.3 2.0 1.9 1.9 1.8 1.7 1.7 1.6

EV/EBITDA 19.4 11.9 8.4 5.9 4.3 3.5 2.7 2.3 2.2 2.2 2.1 2.0 2.0 1.9

P/E 37.6 22.3 15.4 10.6 7.6 11.2 9.5 8.7 8.0 7.3 6.6 6.1 5.5 5.0

2006 2007е 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Electric

capacity,

MW

21 708 24 043 25 073 25 388 26 134 27 365 28 325 29 705 29 705 29 705 29 705 29 705 29 705 29 705 29 705

Electricity

sales,

GWh

73 112 81 495 84 146 87 156 94 096 101 506 108 258 124 175 124 175 124 175 124 175 124 175 124 175 124 175 124 175

Load factor 39% 40% 39% 40% 42% 44% 45% 49% 49% 49% 49% 49% 49% 49% 49%

Effective

electricity

price,

USD/MWh

8 18 26 33 42 52 60 66 77 79 82 85 88 91 95

EBITDA/kW,

USD12 42 66 92 127 165 199 245 286 296 305 315 325 336 346

RusHydro


DCF



Valuation


EBIT 1 390 1 986 2 863 3 953 5 046 6 637 7 849 8 102 8 359 8 625 8 899 9 182 9 475

Tax on EBIT - 334 - 477 - 687 - 949 -3 012 -4 253 -5 248 -5 255 -5 242 -5 209 -5 154 -5 074 -4 965

After tax EBIT 1 056 1 509 2 176 3 004 2 033 2 384 2 602 2 847 3 117 3 415 3 745 4 108 4 510

Depreciation 257 352 446 557 595 626 651 676 703 730 758 786 816

Capex -2 022 -1 439 -1 673 -1 481 - 977 - 610 - 628 - 647 - 666 - 686 - 707 - 728 - 750

Change in WC - 54 37 132 343 - 59 - 78 - 59 - 16 - 16 - 17 - 18 - 18 - 19

FCFF - 763 459 1 081 2 423 1 592 2 322 2 566 2 861 3 138 3 442 3 778 4 149 4 558

Discounted FCFF - 715 382 802 1 597 932 1 209 1 188 1 177 1 148 1 119 1 092 1 066 1 041

WACC 12.5%




Fair EV 22 178

Net debt 2007e adj for state injection 2 960

Minority interest -

Fair MCap 25 391


Upside to FV 13%

12m TP, USD 0.110

Upside to TP 29%

Dividend yield 0.2%



Shares outstanding

(expected after UES breakup), mn 265 739

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 0.128 0.134 0.142 0.151 0.164

11.5% 0.114 0.118 0.124 0.131 0.140

12.5% 0.102 0.106 0.110 0.115 0.121

13.5% 0.092 0.095 0.098 0.102 0.107

14.5% 0.084 0.086 0.089 0.092 0.095

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

10.5% 1 230 1 298 1 382 1 488 1 627

11.5% 1 079 1 129 1 190 1 266 1 361

12.5% 954 992 1 038 1 093 1 161

13.5% 850 879 914 955 1 005

14.5% 762 785 812 843 880

Terminal growth

Existing assets USD/kW New projects Total USD/kW

European Russia 14 912 1 183 260 15 172 1 204

Siberia 7 689 1 072 104 7 793 1 086

Isolated 736 240 57 793 259

Zagorskaya GAES 1 183 986 8 1 190 992

RusHydro total 24 520 1 020 428 24 948 1 038


Plant


Krasnoyarsk GES

6-month performance

Ownership structure

2007 2008e

Assets

Financials

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Krasnoyarskaya GES

RTS Index


Helington Commodities

Ltd.

52%

Elmstone Ventures Ltd.

16%

TGK-1325%

Other minorities

7%

Ownership structure, 2007

Helington Commodities

Ltd.

52%

Elmstone Ventures Ltd.

16%

TGK-1325%

Other minorities

7%

Ownership structure, 2H08e

Company Region

Installed electric

capacity 2007,

MW

Electricity

generation 2007,

GWh

Krasnoyarsk GES Krasnoyarsk 6 000 20 762


Balance sheet

Fixed assets 151 173 260 328 400 467 532 605 677 748 818 887 954 1 020 1 085

Non-cash WC - 4 - 5 - 2 1 13 38 54 75 93 96 99 103 106 110 114

LT investments 15 31 31 30 29 29 28 28 28 28 28 28 28 28 28

Equity 186 218 247 396 720 1 266 1 637 2 115 2 668 3 283 3 967 4 726 5 569 6 506 7 547


Net debt (+) or cash (-) - 17 - 14 48 - 31 - 273 - 727 -1 018 -1 401 -1 864 -2 405 -3 015 -3 703 -4 475 -5 342 -6 315

Other LT liabilities (+) or assets (-) - 7 - 6 - 6 - 6 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5 - 5

Income statement*

Revenues 72 77 102 296 537 851 1 209 1 673 2 079 2 154 2 230 2 308 2 389 2 473 2 561

Electricity 72 77 102 296 536 850 1 209 1 672 2 079 2 153 2 229 2 307 2 389 2 473 2 560

Cost of sales - 48 - 55 - 67 - 79 - 91 - 104 - 112 - 122 - 132 - 142 - 152 - 163 - 174 - 186 - 199

D&A - 3 - 4 - 8 - 12 - 17 - 23 - 27 - 31 - 35 - 39 - 44 - 48 - 53 - 58 - 63

Fixed costs - 45 - 47 - 59 - 66 - 74 - 81 - 85 - 91 - 97 - 102 - 108 - 115 - 121 - 128 - 136

EBITDA 27 24 39 226 459 766 1 120 1 577 1 978 2 047 2 116 2 188 2 262 2 339 2 419

EBIT 24 19 31 213 442 743 1 093 1 547 1 943 2 007 2 072 2 140 2 209 2 281 2 356

EBT 27 20 31 213 442 743 1 093 1 547 1 943 2 007 2 073 2 140 2 209 2 281 2 356

Net income 20 16 24 162 336 564 399 482 559 621 690 766 851 946 1 051

EBITDA margin 38% 31% 38% 76% 86% 90% 93% 94% 95% 95% 95% 95% 95% 95% 94%

EBIT margin 33% 25% 31% 72% 82% 87% 90% 92% 93% 93% 93% 93% 92% 92% 92%

Net margin 28% 20% 23% 55% 63% 66% 33% 29% 27% 29% 31% 33% 36% 38% 41%

Cash flow statement

Change in WC 2 1 - 3 - 3 - 12 - 26 - 17 - 21 - 18 - 3 - 3 - 4 - 4 - 4 - 4

OCF 25 18 29 172 341 562 409 492 575 657 730 811 901 1 000 1 110

Net capex - 11 - 14 - 90 - 93 - 96 - 99 - 102 - 105 - 108 - 111 - 114 - 118 - 121 - 125 - 129

Acquisitions/divestments 0 - 7 0 0 0 0 0 0 0 0 0 0 0 0 0

ICF - 11 - 20 - 90 - 93 - 96 - 99 - 102 - 105 - 108 - 111 - 114 - 118 - 121 - 125 - 129


Change in debt 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

FCF 0 - 2 0 0 0 0 0 0 0 0 0 0 0 0 0

Net CF 13 - 4 - 62 79 245 463 308 387 468 546 616 694 780 875 982


Krasnoyarsk GES


Financial ratios

Operational data

DCF

12m target price


Valuation

2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e

EV/Sales 20.0 15.1 5.2 2.9 1.8 1.3 0.9 0.7 0.7 0.7 0.7 0.6 0.6 0.6

EV/EBITDA 65.4 39.2 6.8 3.4 2.0 1.4 1.0 0.8 0.8 0.7 0.7 0.7 0.7 0.6

P/E 99.8 65.6 9.6 4.6 2.8 3.9 3.2 2.8 2.5 2.3 2.0 1.8 1.6 1.5

2006 2007 2008e 2009e 2010e 2011e 2012e 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e



Load factor 41% 40% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37%


USD/MWh3 4 5 15 28 44 63 87 108 112 116 120 125 129 134

EBITDA/kW, USD 5 4 7 38 77 128 187 263 330 341 353 365 377 390 403


EBIT 31 213 442 743 1 093 1 547 1 943 2 007 2 072 2 140 2 209 2 281 2 356

Tax on EBIT - 7 - 51 - 106 - 178 - 694 -1 065 -1 384 -1 386 -1 383 -1 373 -1 358 -1 335 -1 305

After tax EBIT 24 162 336 564 399 482 559 621 690 766 851 946 1 051

Depreciation 8 12 17 23 27 31 35 39 44 48 53 58 63

Capex - 90 - 93 - 96 - 99 - 102 - 105 - 108 - 111 - 114 - 118 - 121 - 125 - 129

Change in WC - 3 - 3 - 12 - 26 - 17 - 21 - 18 - 3 - 3 - 4 - 4 - 4 - 4

FCFF - 62 79 245 463 308 387 468 546 616 694 780 875 982

Discounted FCFF - 57 63 171 280 161 176 184 187 183 178 174 169 165

WACC 15.3%




Fair EV 3 300

Net debt 2007 14

Minority interest 0

Fair MCap 3 314

FV, USD 8.47

Upside to FV 113%

12m TP, USD 10.1

Upside to TP 153%

Dividend yield 0.2%



Shares outstanding, mn 391

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

13.3% 11.8 12.2 12.7 13.3 14.1

14.3% 10.6 10.9 11.3 11.7 12.3

15.3% 9.51 9.77 10.1 10.4 10.8

16.3% 8.61 8.82 9.06 9.34 9.66

17.3% 7.84 8.01 8.20 8.41 8.66

Terminal growth

WACC 0.0% 1.0% 2.0% 3.0% 4.0%

13.3% 742 770 802 840 887

14.3% 664 685 710 739 774

15.3% 598 615 634 656 683

16.3% 542 555 570 587 608

17.3% 493 503 515 529 545

Terminal growth

Existing assets USD/kW New projects Total USD/kW

Krasnoyarsk GES 3 804 634 0 3 804 634


Plant


Appendix 4: List of figures

Figure 1: Power consumption, government forecast vs. Glitnir ...................................................................................................................................... 5

Figure 2: Load factors, generation companies ............................................................................................................................................................... 6

Figure 3: Effective electricity prices ............................................................................................................................................................................... 7

Figure 4: Valuation summary, Russian generation ........................................................................................................................................................ 9

Figure 5:Summary, foreign generation ........................................................................................................................................................................ 10

Figure 6: Valuation summary, integrated ..................................................................................................................................................................... 11

Figure 7: Valuation summary, distribution ................................................................................................................................................................... 11

Figure 8: Valuation summary, transmission ................................................................................................................................................................. 13

Figure 9: Price performance ........................................................................................................................................................................................ 14

Figure 10: Capacity and generation by country ........................................................................................................................................................... 16

Figure 11: Capacity and generation by type, 2007 ...................................................................................................................................................... 16

Figure 12: Average load factor by type of capacity, 2007 ............................................................................................................................................ 16

Figure 13: Fuel balance in Russia, 2006 ..................................................................................................................................................................... 17

Figure 14: Electricity consumption breakdown, 2007 ................................................................................................................................................... 17

Figure 15: GDP and power consumption ..................................................................................................................................................................... 18

Figure 16: Installed electric capacity, maximum load, reserve margin, Russia total ..................................................................................................... 18

Figure 17: Peak consumption, January 23, 2006 ........................................................................................................................................................ 19

Figure 18: Split of capacity by period of commissioning .............................................................................................................................................. 19

Figure 19: Asset depreciation by segment .................................................................................................................................................................. 19

Figure 20: Average fuel burn rate, Russia total ........................................................................................................................................................... 20

Figure 21: Capex requirements, government base scenario ....................................................................................................................................... 20

Figure 22: UES reorganization .................................................................................................................................................................................... 22

Figure 23: Map of generation companies .................................................................................................................................................................... 24

Figure 24: Consolidation of RusHydro ......................................................................................................................................................................... 25

Figure 25: Interregional power distribution companies (MRSKs) ................................................................................................................................. 26

Figure 26: Distribution segment restructuring .............................................................................................................................................................. 26

Figure 27: Lenenergo shareholder structure, post-additional share issue .................................................................................................................... 27

Figure 28: Additional share issues .............................................................................................................................................................................. 27

Figure 29: FSK consolidation ...................................................................................................................................................................................... 28

Figure 30: Restructuring scheme, timeline .................................................................................................................................................................. 28

Figure 31: Far East Energy Company and isolated AO-energos ................................................................................................................................. 29

Figure 32: Reorganization of Far East and isolated AO-energos ................................................................................................................................. 29

Figure 33: Target structure of Far East and isolated AO-energos ................................................................................................................................ 29

Figure 34: InterRAO Russian power plants ................................................................................................................................................................. 30


Figure 35: Formation of InterRAO ............................................................................................................................................................................... 30

Figure 36: InterRAO ownership after UES breakup ..................................................................................................................................................... 30

Figure 37: UES spinoff structure ................................................................................................................................................................................. 31

Figure 38: Large minorities’ equity swaps during UES breakup ................................................................................................................................... 32

Figure 39: ―For‖ and ―against‖ baskets ........................................................................................................................................................................ 33

Figure 40: Timeline of corporate actions for local shares ............................................................................................................................................. 35

Figure 41: Timeline of corporate actions for depositary receipts .................................................................................................................................. 35

Figure 42: Generation company privatisation deals ..................................................................................................................................................... 37

Figure 43: EV/Capacity implied in deals ...................................................................................................................................................................... 38

Figure 44: Forthcoming placements ............................................................................................................................................................................ 38

Figure 45: Ownership structure of generation assets by installed capacity .................................................................................................................. 39

Figure 46: Ownership by energy zone, European Russia ............................................................................................................................................ 39

Figure 47: Distribution company ownership ................................................................................................................................................................. 39

Figure 48: Supply company auctions .......................................................................................................................................................................... 40

Figure 49: Forthcoming supply company auctions ....................................................................................................................................................... 41

Figure 50: Regulated electricity tariff, 2008e ............................................................................................................................................................... 42

Figure 51: Regulated capacity tariff, 2008e ................................................................................................................................................................. 42

Figure 52: Average growth of power tariffs vs. inflation ............................................................................................................................................... 43

Figure 53: UES profitability since 2001........................................................................................................................................................................ 43

Figure 54: Capacity payment as % of total revenues, 2006 ......................................................................................................................................... 44

Figure 55: Electricity market liberalisation schedule .................................................................................................................................................... 45

Figure 56: Hourly electricity prices and volumes on April 29, 2008 .............................................................................................................................. 46

Figure 57: Seasonal dynamics .................................................................................................................................................................................... 46

Figure 58: Pricing & energy zones .............................................................................................................................................................................. 47

Figure 59: Generation by fuel type, 2007 .................................................................................................................................................................... 47

Figure 60: Electricity price dynamics ........................................................................................................................................................................... 48

Figure 61: Share of heat in total revenues, 2007 ......................................................................................................................................................... 49

Figure 62: GDP growth vs. heat consumption ............................................................................................................................................................. 50

Figure 63: Heat sales, 2006 ........................................................................................................................................................................................ 50

Figure 64: Heat tariff and heat operating profit margin, 2006 ....................................................................................................................................... 51

Figure 65: Fuel balance, Russia total, 2006 ................................................................................................................................................................ 54

Figure 66: Prices by fuel type, 2007 ............................................................................................................................................................................ 54

Figure 67: Gas production by producer, 2007 ............................................................................................................................................................. 54

Figure 68: Gas tariffs by region, 2008 ......................................................................................................................................................................... 55

Figure 69: Penetration of gas transportation network .................................................................................................................................................. 55


Figure 70: Thermal market, by market share ............................................................................................................................................................... 56

Figure 71: Fuel consumption vs. power consumption growth ...................................................................................................................................... 57

Figure 72: Change in average fuel burn rate, government forecast ............................................................................................................................. 57

Figure 73: Government fuel mix forecast ..................................................................................................................................................................... 57

Figure 74: Macro assumptions .................................................................................................................................................................................... 58

Figure 75: Oil and gas prices forecast through 2020 ................................................................................................................................................... 58

Figure 76: Gas tariff hike schedule .............................................................................................................................................................................. 59

Figure 77: Domestic gas price forecast ....................................................................................................................................................................... 59

Figure 78: Domestic fuel price forecast ....................................................................................................................................................................... 60

Figure 79: Government forecast for power consumption growth .................................................................................................................................. 60

Figure 80: Electricity consumption vs. GDP, 2007 (PPP) ............................................................................................................................................ 61

Figure 81: Electricity consumption forecast, Russia total ............................................................................................................................................. 61

Figure 82: Government forecast for installed capacity ................................................................................................................................................. 61

Figure 83: Installed electric capacity ........................................................................................................................................................................... 63

Figure 84: Electricity generation .................................................................................................................................................................................. 63

Figure 85: Average load factor .................................................................................................................................................................................... 64

Figure 86: Merit order curve, 2007 .............................................................................................................................................................................. 65

Figure 87: Merit order curve, 2012e ............................................................................................................................................................................ 65

Figure 88: New-entrant assumptions ........................................................................................................................................................................... 66

Figure 89: Cost of new entrant, total ........................................................................................................................................................................... 66

Figure 90: Cost of new entrant by region ..................................................................................................................................................................... 67

Figure 91: Price dynamics on ATS vs. fuel cost of new entrant ................................................................................................................................... 67

Figure 92: Electricity price forecast ............................................................................................................................................................................. 68

Figure 93: Capacity payment forecast ......................................................................................................................................................................... 69

Figure 94: Total effective price .................................................................................................................................................................................... 69

Figure 95: Heat business operating margin ................................................................................................................................................................. 71

Figure 96: Fuel burn rates in electricity production, 2007 ............................................................................................................................................ 71

Figure 97: Fuel burn rates in heat production, 2007 .................................................................................................................................................... 72

Figure 98: Fixed cost of electric capacity, USD/kW, 2006 and 2011e .......................................................................................................................... 73

Figure 99: Fixed cost of heat capacity, 2006 and 2011e .............................................................................................................................................. 73

Figure 100: Market risk calculation .............................................................................................................................................................................. 74

Figure 101: Discount rate calculation, generation companies ...................................................................................................................................... 75

Figure 102: EBITDA/kW .............................................................................................................................................................................................. 76

Figure 103: Valuation results....................................................................................................................................................................................... 77

Figure 104: Target price sensitivity analysis, generation companies ........................................................................................................................... 79


Figure 105: RCN vs. overall grid size .......................................................................................................................................................................... 81

Figure 106: RCN vs. grid length .................................................................................................................................................................................. 82

Figure 107: RCN vs. electricity throughput .................................................................................................................................................................. 82

Figure 108: RCN and DRC, Russian vs. foreign distribution grids ............................................................................................................................... 83

Figure 109: Capex by source of financing, MRSKs ..................................................................................................................................................... 84

Figure 110: Debt to assets,* 1H07 and 2010e ............................................................................................................................................................. 85

Figure 111: Capital structure, distribution sector ......................................................................................................................................................... 85

Figure 112: Cost of equity calculation, MRSKs ............................................................................................................................................................ 86

Figure 113: Target price calculation, MRSKs .............................................................................................................................................................. 87

Figure 114: Implied distribution tariff, USD/MWh ......................................................................................................................................................... 88

Figure 115: Sensitivity analysis, MRSKs ..................................................................................................................................................................... 89

Figure 116: Peer group, distribution companies .......................................................................................................................................................... 91

Figure 117: RCN and DRC, FSK and foreign peers .................................................................................................................................................... 92

Figure 118: FSK capex through 2012 .......................................................................................................................................................................... 93

Figure 119: Cost of equity calculation, FSK ................................................................................................................................................................. 93

Figure 120: FSK target price calculation ...................................................................................................................................................................... 93

Figure 121: Valuation without capex or state injection ................................................................................................................................................. 94

Figure 122: Target price, regional transmission companies ......................................................................................................................................... 94

Figure 123: Transmission tariff .................................................................................................................................................................................... 94

Figure 124: FSK, revenues ......................................................................................................................................................................................... 94

Figure 125: FSK, EBIT margin .................................................................................................................................................................................... 95

Figure 126: Sensitivity to year of introduction .............................................................................................................................................................. 95

Figure 127: Sensitivity to DRC estimate ...................................................................................................................................................................... 95

Figure 128: Sensitivity to RCN appreciation rate ......................................................................................................................................................... 95

Figure 129: Peer comparison, FSK ............................................................................................................................................................................. 96

Figure 130: Sum-of-parts valuation, independent AO-energos .................................................................................................................................... 97

Figure 131: Sum-of-parts valuation, Far East Energy Company .................................................................................................................................. 98

Figure 132: UES basket indicative valuation ............................................................................................................................................................... 99

Figure 133: MRSK Holding valuation ........................................................................................................................................................................ 100

Figure 134: Sum-of-parts valuation, Far East Energy Holding ................................................................................................................................... 101

Figure 135: Sum-of-parts valuation, InterRAO sum ................................................................................................................................................... 101


Disclosures Glitnir banki hf. and/or Glitnir Securities and/or Glitnir AB and/or Glitnir Pankki Oy and/or CJSC Glitnir Securities and/or their affiliate(s) are or may be regularly doing proprietary trading in equity securities of this company.

The author, or an individual who assisted in the preparation, of this report (or a member of his/her household), or a person who although not involved in the preparation of the report had or could reasonably be expected to have access to the substance of the report prior to its dissemination, has a direct ownership position in securities issued by this company.

Rating ratio

Information on the 12-month rating ratio of this company can be found on local Glitnir websites. www.glitnir.is / www.glitnir.no / www.glitnir.se / www.glitnir.fi / www.glitnir.ru

Recommendation structure

Glitnir employs a four level recommendation structure based on absolute levels and a 12-month horizon:

BUY: Our target price is more than 20% above the current share price

ACCUMULATE: Our target price is between 10% and 20% above the current share price.

HOLD: Our target price is between 0% above and 10% above the current share price.

REDUCE: Our target price is below the current share price.


Disclaimer The information in this report is based on publicly available data and information from various sources deemed reliable by Glitnir banki hf. and/or Glitnir Securities and/or Glitnir AB and/or Glitnir Pankki Oy and/or CJSC Glitnir Securities and/or its affiliate(s), (herein referred to collectively as Glitnir), but has not been independently verified by Glitnir which therefore does not guarantee that the information is comprehensive and accurate.

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Regulators

Glitnir banki hf: The Financial Supervisory Authority of Iceland (www.fme.is)

Glitnir Securities: The Financial Supervisory Authority of Norway (www.kredittilsynet.no)

Glitnir AB: The Financial Supervisory Authority of Sweden (www.fi.se)

Glitnir Pankki Oy: The Financial Supervisory Authority of Finland (www.rahoitustarkastus.fi)

CJSC Glitnir Securities: The Russian Financial Markets Commission (www.fcsm.ru)

RUSSIA

Please bear in mind that investment activity in emerging markets is very risky, and investors should conduct their own due diligence prior to making an investment decision. The individual(s) responsible for the preparation of this Report (the Author(s)), or Glitnir may hold short- and long-term positions in any of the securities mentioned in the Report, and may take part in investment activities with companies mentioned in the Report. In preparing this Report, the Author(s) assumed that the issuers mentioned in the Report disclose information in the amount and under the procedures stipulated by the securities legislation of the Russian Federation for issuers who publicly place securities. This Report and the Information is based exclusively on publicly-available information, which is deemed to be reliable; however, Glitnir makes no representation that this information is accurate or comprehensive, and it should not be relied upon as such. Glitnir makes no representation that this Report has been released to all readers simultaneously, nor that it will update this material on a regular basis or that it will correct inaccuracies contained in this Report.

UNITED STATES

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CANADA

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OTHER COUNTRIES

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Contact Information GLITNIR EQUITY SALES

ICELAND

Ingi Rafnar Juliusson,

Head of Securities +354 440 4459

Elmar Svavarsson +354 440 4452

Karl Finnbogason +354 440 4467

Tryggvi Bjornsso +354 440 4458

NORWAY

Geir Jarle Bjorneng,

Head of Sales +47 2201 6344

Eivind Semb +47 2201 6322

Helge Andresen +47 2201 6307

Joachim Rasmussen +47 2201 6359

Per Henrik Mohn +47 2201 8616

Thomas Lande +47 2201 6336

Oyvind Robberstad +47 2201 6329

SWEDEN

Magnus Hägglund,

Head of Equities +46 8 5601 8880

Claes Österlin +46 8 5601 8940

Hakan Molin +46 8 5601 8700

Gustav Andersson +46 8 5601 8660

Johan Svahn +46 8 5601 8840

Lennert Lindberg +46 8 5601 8860

Patrick Larsson +46 8 5601 8840

FINLAND

Hans Segercrantz,


Kim Sjöström Head of Brokerage +358 9 6134 6304

Henrik Rinta +358 9 6134 6437

Jarmo Riikonen +358 9 6134 6337

Jerome Deponge +358 9 6134 6491

Jorma Torniainen +358 9 6134 6204

Marcus Bjorksten +358 9 6134 6203

RUSSIA

Jussi Seppalä


Ilya Matushkin +7 495 545 0534

Maxim Romodin +7 495 545 0538

Vladimir Mikhailov +7 495 545 0537

GLITNIR RESEARCH

ICELAND e-mail: [email protected]

Almar Gudmundsson MD Glitnir Nordic Research +354 440 4944 Jon Bjarki Bentsson Macro / FX +354 440 4634

Ingolfur Bender Head of research +354 440 4635 Ragnhildur Jonadottir Macro / FX +354 440 4648

Asmundur Gislason Financials +354 440 4768 Sigrun Hjartardottir Project Manager +354 440 4748

Audbjorg Olafsdottir Macro / Iceland Daily +354 440 4699 Sveinn Thorarinsson Financials +354 440 4633

Gretar Mar Axelsson Financials +354 440 4631 Valdimar Halldorsson Food / Seafood +354 440 4638

Hjordis D. Vilhjalmsdottir Macro / Fixed Income +354 440 4689

NORWAY e-mail: [email protected]

Bengt Jonassen Head of research +47 2201 6375 Geir K. Sandes Supply +47 2201 6369

Anders Bergland Oil Services +47 2201 6372 Henning Lund Seafood +47 2201 6347

Arnfinn Lov-Mikkelsen Telecom / IT +47 2201 6373 Marius Kongsgarden Financials +47 2201 6358

Christian Yggeseth Oil +47 2201 6319 Sondre Vevstadt Seafood +47 2201 6321

Dag Kilen Shipping +47 2201 6309 Terje Mauer Industry / Life sciences +47 2201 6324

Daniel Malmberg IT +47 2201 6338

SWEDEN e-mail: [email protected]

Ola Asplund Head of research +46 8 463 85 36 Mats Hyttinge Retail / Service / Transport +46 8 463 85 31

Anders Elgemyr Telecoms / IT +46 8 463 85 23 Ola Olsson Pharma / Biotech +46 8 463 85 06

Bertil Nilsson Construction / Real Estate +46 8 463 85 32 Richard Askehed Macro / Strategy +46 8 463 85 02

Henrik Ekenman Retail / Service +46 8 463 85 33

FINLAND e-mail: [email protected]

Jarkko Soikkeli Head of research +358 9 613 46 447 Jari Westerberg Construction / Media +358 9 613 46 217

Evgeny Artemenkov Markets & data mgmt +358 9 613 46 219 Jonas Spohr Small Caps +358 9 613 46 508

Jaakko Tyrvainen Financials/ Forestry +358 9 613 46 376 Sanna Kaje Engineering /Energy +358 9 613 46 430

RUSSIA e-mail: [email protected]

Andrew Afanasiev Head of research +7 495 545 0535 Ilya Koupreyev Utilities +7 495 545 0535

Anna Sidorova Telecoms +7 495 545 0535 Oksana Lossevskaya Banking +7 495 545 0535

Bahrom Umarbekov Oil & Gas +7 495 545 0535 Sergei Kanin Metals & Mining / Industry +7 495 545 0535

Elizabeth Ashworth Editor/Production Manager +7 495 545 0535 William Gross IT / Media +7 495 545 0535

Dmitry Astakhov Utilities +7 495 545 0535

This contact information includes employees of all Glitnir Bank offices and affiliates as well as ZAO FIM Financial Services. Outside Russia Glitnir Bank Ltd is the disseminator of analysis produced by ZAO FIM Financial Services.

Mika Koskimies +358 9 6134 6427

Thomas Pirker +358 9 6134 6222

initiation 06_25_2008_glitnir

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