Construction of three mini-chp Plants in Moscow region

Transcription

1 Joint Implementation Supervisory Committee JOINT IMPLEMENTATION PROJECT DESIGN DOCUMENT FORM Version 01 - in effect as of: 15 June 2006 Construction of three mini-chp Plants in Moscow region (Moscow region, Russian Federation) Version November 2007

2 Joint Implementation Supervisory Committee page 2 CONTENTS A. General description of the project B. Baseline C. Duration of the project / crediting period D. Monitoring plan E. Estimation of greenhouse gas emission reductions F. Environmental impacts G. Stakeholders comments Annexes Annex 1: Contact information on project participants Annex 2: Baseline information Annex 3: Monitoring plan Annex 4: Reference list

3 Joint Implementation Supervisory Committee page 3 SECTION A. General description of the project A.1. Title of the project: Construction of three mini-chp Plants in Moscow region PDD Version 2.0, dated November 22, 2007 A.2. Description of the project: The essence of the project lies in the construction of cogeneration units on three sites in Moscow region: Lobnya, shopping complex Ashan and Myakinino. All three installations will use cogeneration units (gas engines Jenbacher) and hot water boilers (Hoval), latter for supplying heat when demand is higher than cogeneration units are able to cover. Table A.2.1. Installed capacities of the equipment Equipment Number Total Installed Capacity Heat [MW] Electricity [MW] LOBNYA Cogeneration unit natural gas Hot water boiler Cogeneration unit diesel fuel*) ASHAN Cogeneration unit natural gas Hot water boiler MYAKININO Cogeneration unit natural gas Hot water boiler Cogeneration unit diesel fuel*) *) for emergency purposes only There is no capacity installed on any of the three sites currently that would satisfy increasing demand of heat and electricity. Main Goals of the Project Construction of three cogeneration power plants in out-skirts of Moscow will satisfy increasing power and heat demand in rapidly growing areas. Technology to be installed is highly efficient and provides for flexibility in covering consumers demand. As electricity will be produced in cogeneration units at relatively lower carbon intensity, the project brings CO 2 emission reduction against scenario without the project implemented. There is lack of electricity generation in OEO Mosenergo and in considered areas in particular. Lobnya New cogeneration power plant will satisfy energy demand in industrial area of town Lobnya for base consumers (TetraPack, Metallprofil, Azindor etc.) and for development of industrial enterprises, too. Ashan New cogeneration power plant will satisfy energy demand of shopping complex. Myakinino New cogeneration power plant will satisfy energy demand in new administrative centers (regional court, offices of Min. of Finance), business center, guest-house Rublyovo etc. Implementation schedule and costs of the project Cogeneration units and hot water boilers will be put in operation according to schedule based on rise of demand in respective areas. As new consumers will start their operations in different moments having different energy demand, installation of cogeneration units will respect

4 Joint Implementation Supervisory Committee page 4 consumers' plans. Number of units in operation in sequenced time periods (3 months quarter of year) is shown in following table: Table A.2.2. Beginning of operation of the equipment LOBNYA ASHAN MYAKININ O Number of units in operation CGU HWB CGU HWB CGU HWB 2007 Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q1*) *) all planned units in operation already CGU cogeneration unit (combustion engine) HWB hot water boiler Table A.2.3. The total cost of the project mln. Lobnya Ashan Myakinino A.3. Project participants: Party involved Legal entity project participant (as applicable) Kindly indicate if the Party involved wishes to be considered as project participant (Yes/No) No Russian Federation Close JSC NATEC (Host party) Switzerland Cargill International SA No

5 Joint Implementation Supervisory Committee page 5 NATEC Group of companies NATEC provides for customers engineering services in area of energy industry and ecology. Most important task of NATEC is implementation of projects aimed to improve energy efficiency at lower environmental impacts. Cargill International SA Cargill is an international provider of food, agriculture and risk management products and services. With employees in 63 countries, the company is committed to using its knowledge and experience to collaborate with customers to help them succeed. The emissions team is a part of the Power&Gas Trading Desk within Cargill International SA, Geneva and helps to originate (through Cargill Emission Reduction Services in Minneapolis), develop and market emission reductions from JI and/or CDM projects around the world. To date, the emissions team has developed a diversified portfolio of projects from more than 10 countries and methodologies. With over US$300 million worth of investments in the food and agricultural sectors in Russia, Cargill is one of the leading foreign investors in Russia and regularly looks for existing and future JI projects to add to its already strong commercial presence in Russia. A.4. Technical description of the project: A.4.1. Location of the project: The three projects are located in outskirts of Moscow, in Moskovskaya Oblast, which is situated in the center of European part of the Russian Federation. A Host Party(ies): Russian Federation. Moscow Region A Region/State/Province etc.: A City/Town/Community etc.: City of Moscow, Lobnya town, Krasnogorsk town. A Detail of physical location, including information allowing the unique identification of the project (maximum one page): The project's individual installations will be located in three sites as follows: Lobnya Lobnya is a town in Moscow Region, located some 27 km north of Moscow. Population: approx. 66,000. International airport Sheremetyevo is located in Lobnya district. Power plant that is subject of the project is located in town of Lobnya, Krasnopolyanskaya Street. Ashan The shopping complex Ashan is located at Novoukhtomskoe road, sub district Kosino-Ukhtomskiy, Eastern Administrative District of Moscow (EAD). EAD with area of km 2 occupies 14.4% of metropolitan territory having population mln.

6 Joint Implementation Supervisory Committee page 6 Myakinino Power plant Myakininskaya poyma (Myakinino) will be situated in municipal area of Krasnogorsk. Krasnogorsk district is located on north-western outskirt of City of Moscow. Lobnya Myakinino MOSCOW Ashan Fig. A Location of the project A.4.2. Technology(ies) to be employed, or measures, operations or actions to be implemented by the project: The essence of the project is installation of advanced Jenbacher gas engines (cogeneration units) for production of electricity and heat in all three project sites. Jenbacher type 6 engines are advanced products serving the 1.8 to 3 MW power range. Its 1,500 rpm engine speed results in a high power density and low installation costs. The type 6 pre-combustion chamber with lean burn control achieves maximum efficiency with low emissions. The type 620 planned for installation is equipped with 20 cylinders. For situations when cogeneration units do not produce sufficient amount of heat to satisfy demand, there will be installed hot water boilers Hoval with installed capacity 8 MW each. Additional diesel generators will be installed for emergency situations of interruption of gas supply. These diesel generators will not be operated during normal situations. The values of power and heat output presented in the Table A are taken from [1, 2, 3] are calculated in accordance with Methodological guidelines on determination of consumption of fuel, electricity and water for heat output by heating boiler houses of heat-and-power engineering enterprises developed by researching institute named after Pamfilov. These calculations [1, 2, 3] are arranged according to the requirements stated in Annex of [4].

7 Joint Implementation Supervisory Committee page 7 Table A Installed equipment AFTER full implementation of the project: Installed capacity Number Equipment Type Heat Electricity [MW] [MW] LOBNYA 12 Cogeneration unit JMS 620 Jenbacher 12 x x Diesel generator unspecified 1 x Hot water boiler THW-I NTE 90/80/10 Hoval 3 x 8.0 ASHAN 10 Cogeneration unit JMS 620 Jenbacher 10 x x Hot water boiler THW-I NTE 90/80/10 Hoval 2 x 8.0 MYAKININO 10 Cogeneration unit JMS 620 Jenbacher 10 x x Diesel generator unspecified 1 x Hot water boiler THW-I NTE 90/80/10 Hoval 3 x 8.0 Table A Annual output after full project implementation Equipment Electricity Heat produced/supplied [MWh] [GJ] LOBNYA Cogeneration units Hot water boilers ASHAN Cogeneration units Hot water boilers MYAKININO Cogeneration units Hot water boilers TOTAL Fuel: natural gas A.4.3. Brief explanation of how the anthropogenic emissions of greenhouse gases by sources are to be reduced by the proposed JI project, including why the emission reductions would not occur in the absence of the proposed project, taking into account national and/or sectoral policies and circumstances: The anthropogenic emissions of greenhouse gases by sources are to be reduced by the proposed JI project by increasing energy (electricity) generation efficiency. The amount of electricity produced under project scenario ( MWh annually after full implementation of the project) would be generated under baseline scenario by power plants that are part of Consolidated Energy System (CES) of Center. The CES of Center generates electricity with higher CO 2 emission factor than cogeneration units intended for the project. Therefore project implementation will lead to less CO 2 emission from electricity generation. In the baseline scenario heat needed in facilities close to project sites is generated by hot water boilers at high efficiency. In case of project, certain share of heat will come from cogeneration units produced at slightly lower efficiency. Thus in the project scenario the same quantity of heat will be produced at higher CO 2 emissions. However, this increase will be far outweighed with emission reduction due to electricity produced with higher efficiency.

8 Joint Implementation Supervisory Committee page 8 Table A Emission factors *) Emission factor for electricity [tco 2 /MWh] Baseline scenario (grid) Project scenario (cogeneration units combustion engines) Emission factor for heat [tco 2 /GJ] Baseline scenario (hot water boilers) Project scenario (cogeneration units+boilers) *) emission factor decreases within Therefore, if project is not implemented, production of the quantity of electricity and heat would lead in total to higher CO 2 emissions. A Estimated amount of emission reductions over the crediting period: Years Length of the crediting period 5 Year Estimate of annual emission reductions in tonnes of CO 2 equivalent TOTAL Annual average A.5. Project approval by the Parties involved: The project will be approved by Russian Federation after passing of the Russian procedure of the Project registration as JI project. The Parties Approval Letters will be received later.

9 Joint Implementation Supervisory Committee page 9 SECTION B. Baseline B.1. Description and justification of the baseline chosen: The methodology of the carbon intensity calculation: The baseline and project GHG emissions are evaluated on a series of key factors which have the potential to affect the baseline development, the project activity level and therefore GHG emissions. In the baseline methodology is used the build margin (BM) and operating margin (OM) approach as specified in ACM0002 Consolidated methodology for grid-connected electricity generation from renewable sources and makes reference to the latest approved version of the tool for the demonstration and assessment of additionality (version 3). The leakages baseline calculation was based on the methodology AM0029 Baseline Methodology for Grid Connected Electricity Generation Plants using Natural Gas. For more information regarding the proposal and its consideration by the JI Supervisory Committee please refer to For the baseline determination were taken into account CO 2 emissions from electricity generation displaced due to the project activity in fossil fuel power plants. The baseline emission factor (EFy) is calculated as a combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) factors. Calculations for this combined margin is based on data from an official source, where available and made publicly available. Dispatch data are not available. Calculation of the Operating Margin emission factors (EFOM,simple,y) is based on the Simple OM method as the generation-weighted average emissions per electricity unit (tco 2 /MWh) of all generating sources serving the system, not including low-operating cost and must-run power plants: Where: Fi, j, y is the amount of fuel i (in a mass or volume unit) consumed by relevant power sources j in year(s) y, j refers to the power sources delivering electricity to the grid, not including low-operating cost and must run power plants, and including imports to the grid, COEFi,j y is the CO2 emission coefficient of fuel i (tco 2 / mass or volume unit of the fuel), taking into account the carbon content of the fuels used by relevant power sources j and the percent oxidation of the fuel in year(s) y, and GENj,y is the electricity (MWh) delivered to the grid by source j. The CO 2 emission coefficient COEFi is obtained as COEFi = NCVi * EFCO2,i * OXIDi Where: NCVi is the net calorific value (energy content) per mass or volume unit of a fuel i, OXIDi is the oxidation factor of the fuel (see page 1.29 in the 1996 Revised IPCC Guidelines for default values), EFCO2,i is the CO 2 emission factor per unit of energy of the fuel i. For calculation are used local values of NCVi and IPCC default values EFCO2,i.

10 Joint Implementation Supervisory Committee page 10 Calculation of the Build Margin emission factor (EFBM,y) as the generation-weighted average emission factor (tco 2 /MWh) of a sample of power plants m, as follows: Where: Fi,m,y, COEFi,m and GENm,y are analogous to the variables described above for plants m. For estimating of the Build Margin emission factor EFBM,y the Option 2 has been chosen the Build Margin emission factor EFBM,y must be updated annually ex-post for the year in which actual project generation and associated emissions reductions occur The sample group m consists of the five power plants that have been built most recently. Calculation of the baseline emission factor (EFy) as the weighted average of the Operating Margin emission factor (EFOM,y) and the Build Margin emission factor (EFBM,y): EFy = wom * EFOM, y + wbm *EFBM, y where the weights wom and wbm, by default, are 50% (i.e., wom = wbm = 0.5), and EFOM,y and EFBM,y are calculated as described above and are expressed in tco 2 /MWh. Calculation of carbon intensity of the selected grid: Calculation of Operating Margin emission factors (EFOM,simple,y) was based on analysis of structure of set of power plants grouped in CES of Center. For this purpose number of 77 fossil fuel power plants within OES Center was selected out of regional generating companies from regions Belgorod, Bryansk, Orel, Ryazan, Smolensk, Tambov, Tula, Voronezh, Kaluga, Kursk, Lipetsk, Nizhy Novgorod, Vladimirsk, Moscow, Ivanovo, Yaroslavl, Tver, Kostroma, Vologda. Low-cost power plants preferably connected to grid (renewable energy sources) were not included in selection. Total capacity of sources within OES Center is MW. Installed capacity of selected fossil fuel power plants is MW (66%), capacity of nuclear, hydro and biomass power plants is MW (28%). Remaining capacity belongs to industrial power plants with capacity MW (5.5%). There is surplus installed capacity in OES Center MW. Average EF OM for years were calculated according to Simple OM methodology using amount of produced electricity, fuel consumed, heating values and CO 2 emission factors at each single power plant (77 plants). Table B.1.1. Operating Margin emission factors (EFOM) calculated according to the Simple OM method: Year Electricity mln.kwh Emission tco EFOM tco 2 /MWh Table B.1.2. Operating Margin emission factors (EFOM) forecast for period : Year EFOM tco 2 /MWh The Build Margin emission factor (EFBM) was calculated from data on amount of produced electricity, fuel consumption, heat content values and CO 2 emission factors for each out of five power plants most recently put in operation in CES of Center:

11 Joint Implementation Supervisory Committee page 11 Table B.1.3. Data on amount of produced electricity, fuel consumption, heat content values and CO 2 emission factors Power plant Year Electricity mln.kwh Emission tco 2 EFBM tco 2 /MWh Sochi TPP GTU CHPP Luch Severo- Zapadnaya CHPP Tyumenskaya PGU-190/220 st Nizhnevartovskaya TPP (blok No.2 ) TOTAL Calculated baseline emission factor (EFy) as the weighted average of the Operating Margin EFOM and the Build Margin EFBM: Table B.1.4. Calculated baseline emission factor (EFy) Year EFOM tco 2 /MWh EFBM tco 2 /MWh EF tco 2 /MWh B.2. Description of how the anthropogenic emissions of greenhouse gases by sources are reduced below those that would have occurred in the absence of the JI project: For assessment of additionality in identified alternatives the Tool for demonstration and assessment of additionality (version 3) has been applied. Assessment is based on Investment and sensitivity analysis for demonstration that the anthropogenic emissions of the greenhouse gases are reduced below those that would have occurred in the absence of the JI project. Step 1: Identification of alternatives to the project activity consistent with current laws and Regulations Sub-step 1a. Define alternatives to the project activity: Alternatives that are not JI and that provide outputs or services comparable with the proposed JI project activities are: Alternative 0 - The proposed project is not undertaken as JI project. Alternative 1 - No energy centers with cogeneration units will be constructed and consumers will be supplied by electricity from public grid and by heat from heat network. Alternative 2 - No cogeneration units will be constructed and consumers will be supplied by electricity from public grid and new boiler houses will be built for supplying heat. Alternative 0 - The proposed projects are not undertaken as JI project implementation of projects without being treated as JI would mean drop in income within period of approx.: Lobnya: Ashan: Myakinino:

12 Joint Implementation Supervisory Committee page 12 Such a shortfall would affect projects adversely during start phase in particular, as financial resources come from loans with 12% interest rate. Alternative 1 - It is considered that within Alternative 1 neither energy centre (Lobnya, Ashan, Myakinino) equipped with cogeneration unit will be constructed. Consumers in respective areas will be supplied by electricity from public grid and heat from centralized district heating systems. As an advantage, no investment resources (involving bank loan) are needed (with the exception of cost of pipeline connection to district heating grid) and pollutant emissions into the atmosphere on sites will not increase. A disadvantage of Alternative 1 is relatively high fee (in addition to electricity price) for 1 kwh increase in electricity consumption and consumers' entire dependence on electricity and heat supply from public grids. Table B.2.1. Alternative 1 parameters LOBNYA Indicators Unit Heat from centralized system thous. GJ Electricity from grid MWh Combined EFCO 2 (heat Moscow RDC) tco 2 /GJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco ASHAN Indicators Unit Heat from centralized system thous. GJ Electricity from grid MWh Combined EFCO 2 (heat Moscow RDC) tco 2 /GJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco MYAKININO Indicators Unit Heat from centralized system thous. GJ Electricity from grid MWh Combined EFCO 2 (heat Moscow RDC) tco 2 /GJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco Alternative 2 - It is considered that within Alternative 2 neither energy centre (Lobnya, Ashan, Myakinino) will be equipped with cogeneration unit. Only hot water boilers for heat and water supply will be constructed. Consumers in respective areas will be supplied by electricity from public grid. As an

13 Joint Implementation Supervisory Committee page 13 advantage, only moderate investment resources are needed and pollutant emissions into the atmosphere on sites will be lower than in the project scenario. A disadvantage of Alternative 2 is relatively high fee (in addition to electricity price) for 1 kwh increase in electricity consumption and consumers' entire dependence on electricity supply from public grid. Table B.2.2. Alternative 2 parameters LOBNYA Indicators Unit Heat from new boiler house thous. GJ Electricity from grid MWh EFCO 2 for NG tco 2 /TJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco ASHAN Indicators Unit Heat from new boiler house thous. GJ Electricity from grid MWh EFCO 2 for NG tco 2 /TJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco MYAKININO Indicators Unit Heat from new boiler house thous. GJ Electricity from grid MWh EFCO 2 for NG tco 2 /TJ CO 2 emission from heat tco Combined EFCO 2 (electricity) tco 2 /MWh CO 2 emission from electricity tco Baseline CO 2 emission tco Alternative 0 is not viable alternative and it will be eliminated from consideration. Further on, option Alternative 1 and Alternative 2 are considered. Sub-step 1b. Enforcement of applicable laws and regulations: All remaining alternatives fully meet the requirements of the Russian legislation on power supply and its implementation is fully under control of CJSC NATEC (the owner of the CHPP Lobnya, CHPP Ashan, and CHPP Myakinino). CJSC NATEC has all necessary licenses for that. 1. Regulations and Standards of construction and operation of energy plants.

14 Joint Implementation Supervisory Committee page 14 These documents establish standards of secure operation of plant equipment. They can have both state and sectoral status, they establish terms of inspections. Fulfillment of regulations and standards are under control of state entities and executives of CHPP Lobnya, CHPP Ashan, and CHPP Myakinino. In case of non-compliance the defects (for instance, deterioration) must be eliminated. 2. Environmental legislation. The Environmental legislation (both state and local requirements) establish individual emission and water discharge limits as well as payments for emissions and discharge within the limits and over the limits. Annually states supervising environmental entities hold inspections. The instructions issued by those entities are obligatory for implementation. The existing environmental legislation: Federal Law On protection of Atmosphere Air of April 22, 1999; The Order of the Minister of Environmental and Natural Resources of November 27, 1992 Basic regulations of payments for emissions, water discharge and waste disposal ; Federal Law On Environmental Protection of December 26, Conclusion: The existing modes and operational conditions of CHPP Lobnya, CHPP Ashan, and CHPP Myakinino are most probable and realistic for all remaining alternatives. These alternatives are in compliance with all of existing legislation and regulations requirements. Step 2. Investment analysis As the proposed project activity generates heat and electricity, i.e. it generates economical benefit other than JI project related income the investment comparison analysis (Option II) will be applied. Sub-step 2a. Option I. Apply simply costs analysis Not applicable Sub-step 2b. Option II. Apply investment comparison analysis Two financial indicators are identified for this project type IRR and NPV as in the power sector of the Russian Federation the very financial indicators are key parameters under decision-making of the project implementation. Sub-step 2c. Calculation and comparison of financial indicators The following parameters were used to assess whether the different scenarios for the JI project are credible and plausible: Table B.2.3. Key information used to assess the different baseline alternatives Parameters Unit Natural Gas EUR/1000 m Electricity EUR/MWh Heat EUR/GJ Lobnya Heat Output Alt.1 thous. GJ Electricity Output Alt.1 MWh/a Heat Output Alt.2 thous. GJ Electricity Output Alt.2 MWh/a Electricity from grid Alt.1,2 MWh/a Ashan Heat Output Alt.1 thous. GJ Electricity Output Alt.1 MWh/a

15 Joint Implementation Supervisory Committee page 15 Heat Output Alt.2 thous. GJ Electricity Output Alt.2 MWh/a Electricity from grid Alt.1,2 MWh/a Myakinino Heat Output Alt.1 thous. GJ Electricity Output Alt.1 MWh/a Heat Output Alt.2 thous. GJ Electricity Output Alt.2 MWh/a Electricity from grid Alt.1,2 MWh/a For the project activity has been apply Investment comparison analysis based on the Net Present Value during 20-years period. In this case a discount rate of 10 % is chosen, the rate of inflation 8.5 % and reference rate of 12 % in line with Russian commercial bank rates. The total investment costs of the projects are: Lobnya: mln. Ashan: mln. Myakinino: mln. (applied Central Bank of Russia exchange rate 34.71). Incomes from ERUs sales are: Lobnya: mln. Ashan: mln. Myakinino: mln. (price = 7 /ERU) Table B.2.4. The IRR and NPV analysis results (% and mln. ) Project analysis Without ERU sales and After ERU sales Project IRR incl.erus sales IRR without ERUs sales NPV incl. ERUs sales NPV without ERUs sales CHPP Lobnya 14.3% 14.1% mln mln. CHPP Ashan 10.9% 10.8% mln mln. CHPP Myakinino 11.9% 11.8% mln mln. The obtained indicators generally confirm that all projects are viable. These figures show that the revenue from the sale of ERUs the project improve economic indicators NPV and IRR. Table B.2.5. Sensitivity analysis Projects analysis (IRR) - Lobnya Lobnya Fluctuation Parameter 10% 5% 0% -5% -10% Investment costs 12.6% 13.3% 14.1% 15.1% 15.9% Fuel costs 13.8% 14.0% 14.1% 14.3% 14.4% Electricity price 15.2% 14.7% 14.1% 13.6% 13.0% Heat price 15.0% 14.6% 14.1% 13.7% 13.3%

16 Joint Implementation Supervisory Committee page 16 IRR 16.0% 15.5% 15.0% 14.5% 14.0% 13.5% 13.0% 12.5% 12.0% 10% 5% 0% -5% -10% Investment costs Fuel costs Electricity price Heat price Fluctuation Table B.2.6. Sensitivity analysis Projects analysis (IRR) - Ashan Ashan Fluctuation Parameter 10% 5% 0% -5% -10% Investment costs 9.4% 10.1% 10.8% 11.5% 12.3% Fuel costs 10.5% 10.6% 10.8% 10.9% 11.1% Electricity price 11.8% 11.3% 10.8% 10.3% 9.7% Heat price 11.6% 11.2% 10.8% 10.4% 10.0% IRR 13.0% 12.5% 12.0% 11.5% 11.0% 10.5% 10.0% 9.5% 9.0% 10% 5% 0% -5% -10% Investment costs Fuel costs Electricity price Heat price Fluctuation Table B.2.7. Sensitivity analysis Projects analysis (IRR) - Myakinino Myakinino Fluctuation Parameter 10% 5% 0% -5% -10% Investment costs 10.3% 11.0% 11.8% 12.6% 13.4% Fuel costs 11.5% 11.6% 11.8% 11.9% 12.0% Electricity price 12.9% 12.3% 11.8% 11.2% 10.5% Heat price 12.5% 12.1% 11.8% 11.3% 10.9%

17 Joint Implementation Supervisory Committee page 17 IRR 14.0% 13.5% 13.0% 12.5% 12.0% 11.5% 11.0% 10.5% 10.0% 10% 5% 0% -5% -10% Fluctuation Investment costs Fuel costs Electricity price Heat price Sensitivity analysis was applied to evaluate sensitivity of the project to changes that might occur during project implementation and operation. A typical example is change of investment cost, which could affect project IRR due to its sensitivity to higher cash flows during first couple of years of the project operation. Analysis of the investment cost within range +10% and -10% showed IRR changes as follows: Lobnya: 12.6% % Ashan: 9.4% % Myakinino: 10.3% % These values for Lobnya are higher that project loan interest rate (12%). IRR values for Ashan and Myakinino are marginal and crucial for their increase will be income from ERUs sale in order enabling projects to generate sufficient income to repay the loan and bring profit. Another factor that might influence project IRR and NPV significantly is change of fuel (natural gas) price above projected price range. Based on analysis, within +10% and -10% change of fuel price IRR values range as follows: Lobnya: 13.8% % Ashan: 10.5% % Myakinino: 11.5% % The conclusion is the same as in above case. Electricity and heat are produced by the project after its implementation, therefore changes of their prices affect project IRR and NPV the opposite way as it is in the case of investment cost change and natural gas price change. As it is widely forecasted, price of electricity, heat and natural gas will grow. If natural gas price grows significantly, increased expenses will be compensated by increased heat and electricity prices. Selection of baseline scenario: There were 2 alternatives considered for baseline emission estimation, i.e. in absence of the project: Alternative 1 - No energy centers with cogeneration units will be constructed and consumers will be supplied by electricity from public grid and by heat from heat network. Alternative 2 - No cogeneration units will be constructed and consumers will be supplied by electricity from public grid and new boiler houses will be built for supplying heat. Only for the Alternative 2 has been applied Investment comparison analysis based on the Net Present Value during 20-years period.

18 Joint Implementation Supervisory Committee page 18 Table B.2.8. Baseline analysis Alternative 2 IRR NPV Lobnya 29.4% mln. Ashan 20.7% mln. Myakinino 19.6% mln. It is considered that within Alternative 1 neither energy centre (Lobnya, Ashan, Myakinino) equipped with cogeneration unit will be constructed. Consumers in respective areas will be supplied by electricity from public grid and heat from centralized district heating systems. As a disadvantage, construction of pipeline connection to district heating grid would be necessary and relatively high fee (45 thous. RUB for 1 kwh) for increase of electricity consumption from JSC Mosenergo would have to be paid and also long-term (at least 5 years) contract should be signed with electricity supplier. Similarly, within Alternative 2 consumers in respective areas will be supplied by electricity from public grid, but within short timeframe hot water boilers for heat and water supply would be constructed, thus avoiding costly construction of pipeline connection to district heating grid. Economic indicators NPV and IRR for Alternative 2 are higher than in case of the project. Based on these considerations the Alternative 2 appears being most plausible scenario in absence of the project and therefore representing baseline scenario. Table B.2.9. Baseline CO 2 emissions Parameters Years Unit Lobnya tco Ashan tco Myakinino tco Total project NATEC tco Step 4: Common practice analysis. Sub-step 4a. Analyse other activities similar to the proposed project activity: No data related to similar activities as the project are available. Sub-step 4b. Discuss any similar options that are occurring: No data related to similar activities as the project are available. Conclusion: Similar activities cannot be observed, then the proposed project activity is additional. B.3. Description of how the definition of the project boundary is applied to the project: The project boundaries represent a list of enterprises, sites, installations and processes, which, to some extent, are associated with the project implementation and influence the GHG emissions. All GHG emissions within the project boundaries should be monitored by the project developer and can be related to the project activity. For the baseline determination shall only account CO 2 emissions from electricity generation in fossil fuel fired power plants that is displaced due to the project activity and CO 2 emissions from heat generation in the absence of the project activity. Present electricity production is carried out in boundaries of energy systems. The energy system is a complex jointly working power plants and networks, with the general mode of operation and the centralized dispatching management. Some working energy systems connected by a generality of a mode

19 Joint Implementation Supervisory Committee page 19 form energy system. The Consolidated Energy Systems (CES) is the term accepted in Russia and understood as some parallel working energy systems having the general mode and centralized dispatching management. Fig. B.3.1. Scheme of UES of Russia with dividing into the Consolidated Energy Systems The basic part of Russia energy systems is incorporated for parallel work within the limits of CES and UES of Russia. In structure of UES of Russia are 6 Consolidated Energy Systems: Centre, Middle Volga, Ural, North-West, South, Siberia. CES of Siberia has been transferred in 1996 into the separate work with UES of Russia and is included in parallel work in 2000 through networks CES of Kazakhstan. CES of Far East works separately from UES of Russia. Technical basis of UES of Russia is as follows: 440 power plants of MW general capacity, including the nuclear power plants of MW, generating 787 billion kwh of electricity in year; transmission lines in the general extent 3018 thousand km; unified system of dispatching regulation, uniting practically all energy entities in work with unified electric frequency 50 Hz.

20 Joint Implementation Supervisory Committee page % 90% 10,9% 11,6% 14,7% 15,7% 80% 15,4% 70% 20,6% 18,7% 17,8% 60% 50% 40% 73,7% 30% 67,8% 66,6% 66,5% 20% 10% 0% TPP HPP NPP Fig. B.3.2. The production structure of electricity during the years Lobnya CHPP Ashan CHPP Myakinino CHPP CO 2 Electricity The Project boundaries Networks of energy system Fuel CO 2 e Transfer CO 2 TPPs Replaced Capacities Electricity Consumer Fig. B.3.3. The project boundaries Table B.3.1. Sources of GHG emissions Baseline Project Activity Source Gas Included? Justification / Explanation Power generation CO 2 Yes Main emission source in baseline CH 4 No Excluded for simplification. This is conservative (Please, see explanation below) On-site fuel combustion activity N 2 O No Excluded for simplification. This is conservative (Please, see explanation below) CO 2 Yes Main emission source CH 4 No Excluded for simplification (Please, see explanation below) N 2 O No Excluded for simplification (Please, see explanation below)

21 Joint Implementation Supervisory Committee page 21 In the power industry in firing fossil fuel the following GHGs are emitting: СО 2, CH 4 and N 2 O. The СО 2 emission coefficients for different fuels fired at the Russian TPPs were determined in the Inventory of GHG emissions from TPPs and boiler plants of the «electric power industry» branch in Russia ( ) : the average weighted СО 2 emissions coefficient in firing natural gas was 1.62 t СО 2 /tce (55.29 t/tj), firing heavy oil 2.28 t СО 2 /tce (77.82 t/tj), and firing coal 2.76 t СО 2 /tce (94.2 t/tj). The total value of the GHG emissions is expressed in СО 2 e. CH 4 and N 2 O emissions in firing fuel can be estimated using the emission coefficient recommended by IPCC (GWP CH4 = 21 tco 2 e/t CH 4, GWP N2O = 310 tco 2 e/t N 2 O): in firing natural gas: K СН4 = 1 kg СН 4 /TJ = 21 x 1 = 21 kg CO 2 /TJ; K N2O = 0.1 kg N 2 O/TJ = 310 x 0.1 = 31 kg CO 2 /TJ; in firing coal: K СН4 = 1 kg СН 4 /TJ = 21 x 1 = 21 kg CO 2 /TJ; K N2O = 1.4 kg N 2 O/TJ = 310 x 1.4 = 434 kg CO 2 /TJ; in firing heavy oil: K СН4 = 3 kg СН 4 /TJ = 21 x 3 = 63 kg CO 2 /TJ; K N2O = 0.6 kg N 2 O/TJ = 310 x 0.6 = 186 kg CO 2 /TJ. Share of respective gas on total GHG emission per TJ is calculated as follows: Gas % = 100 % K K Gas, Fuel Gas, Fuel Results after applying above formula: Natural gas K Gas, NG = Coal K Gas, Coal = Heavy oil K Gas, Heavy oil = Gas CH 4 N 2 O % % Highest CH 4 emission as CO 2 e occurs at burning of heavy oil only (0.08%); highest N 2 O emission as CO 2 e occurs at burning of coal only (0.46%) (both relative to total GHG emissions as CO 2 e). Therefore, share of CH 4 + N 2 O emissions as CO 2 e would in no case exceed 0.54% of total GHG emissions. Under ERUs calculation there is the rule that if some kind of emission amounts less than 1 % then these emissions can not be considered. Thus, this kind of emission can be eliminated from consideration. This rule is applied for other kinds of GHG emissions, for example, for emissions from auxiliary facilities, emissions due to energy consumption for fuel transportation and other indirect emissions if its share amounts less than 1 %.

22 Joint Implementation Supervisory Committee page 22 B.4. Further baseline information, including the date of baseline setting and the name(s) of the person(s)/entity(ies) setting the baseline: Date of completion of the PDD: 22 November 2007 The following entities set the baseline: Close JSC NATEC General Director Mr. Alexey E. Alexeev Address: 19, Malaya Pirogovskaya street, , Moscow, Russia Tel Energy Carbon Fund General Director Mr. Andrey V. Gorkov Address: 101/3, prospect Vernadskogo, , Moscow, Russia Tel PROFING s.r.o. Managing Partner - Ivan Mojik Address: Mliekarenska 10, Bratislava, Slovakia Telephone: mojik@profing.eu

23 Joint Implementation Supervisory Committee page 23 SECTION C. Duration of the project / crediting period C.1. Starting date of the project: Implementation of the Project will start on: Lobnya: 2008 Ashan: 2008 Myakinino: September 2007 C.2. Expected operational lifetime of the project: Lobnya: 50 years Ashan: 50 years Myakinino: 50 years However, the technical lifetime of the main elements of the turbines is determined by the sectoral normative documents of the Russian Federation and is several times longer than the crediting period. Therefore equipment lifetime does not determine emission reductions by the project. C.3. Length of the crediting period: 5 years/60 months (Kyoto Protocol first commitment period from 1 January 2008 to 31 December 2012).

24 Joint Implementation Supervisory Committee page 24 SECTION D. Monitoring plan D.1. Description of monitoring plan chosen: The monitoring is required to determine the operating margin (OM) in step 1 of the Consolidated baseline methodology (ACM0002) "Simple OM" (defined in step 1a); as well as the "BM" a data vintage based on ex - ante monitoring and all parameters will be required for recalculation of the combined margin at crediting period using steps 1-3 in the baseline methodology. Main data sets used for calculation of baseline emissions are as follows: Electricity generation from the proposed project activity Heat generation from the proposed project activity Data needed to recalculate the operating margin emission factor Data needed to recalculate the build margin emission factor The methodology requires monitoring of the following: For Project Activity Scenario: 1. Annual natural gas consumption in project activity. 2. Net Calorific Value of the natural gas used in the project activity 3. Natural gas emission factors used in the project activity. 4. Oxidation factor of natural gas used in project activity. 5. Annual quantity of electricity generated in project activity. 6. Annual quantity of heat generated in project activity. For Baseline Scenario: 1. Annual electricity generated by power plants in the build margin of the project grid. 2. Amount of fuel consumed by the corresponding power plant 3. Net calorific value of fuel used in a power plant. 4. Oxidation factor of fuel used in a power plant 5. CO 2 emission factor per unit of energy of fuel used in a power plant. 6. Annual electricity generated by power plant in the operating margin of the project activity and exporting grid.

25 Joint Implementation Supervisory Committee page 25 D.1.1. Option 1 Monitoring of the emissions in the project scenario and the baseline scenario: D Data to be collected in order to monitor emissions from the project, and how these data will be archived: ID number (Please use numbers to ease crossreferencing to D.2.) 1. FC y 2. NCV NG,y Data variable Source of data Data unit Measured (m), calculated (c), estimated (e) Annual quantity of natural gas consumed in project activity Net Calorific Value of Natural gas Fuel flow meter reading at project boundary Fuel Supplier, Local Authority, Country specific, IPCC Recording frequency Proportion of data to be monitored How will the data be archived? (electronic/ paper) m 3 m Daily 100% Electronic/ paper Comment The total fuel consumption will be monitored both at supplier and project end for crossverification. GJ/m 3 e Fortnightly 100% Electronic Use supplierprovided data, local data, country-specific values, in that order of preference. IPCC values can be used for startup fuel. 3. OXID NG Oxidation factor IPCC -- e Annual 100% Electronic IPCC current default

26 Joint Implementation Supervisory Committee page EFCO2 NG,y 5. COEF NG,y Emission factor for Natural gas CO 2 emission coefficient Local/ Regional/ Global (IPCC) Calculated under project activity tco 2 /GJ e Annual 100% Electronic Supplierprovided data, local data, country-specific values, in that order of preference. IPCC values can be used for startup fuel. tco 2 /m 3 c Annual 100% Electronic 6. PE y Project emission due to combustion of fuel Calculated under project activity tco 2 c Annual 100% Electronic D Description of formulae used to estimate project emissions (for each gas, source etc.; emissions in units of CO 2 equivalent): The project activity is on-site combustion of natural gas to generate electricity and heat. The CO 2 emissions from electricity and heat generation (PE y ) are calculated as follows: PE y = FC y * COEF NG,y Where: FC y : is the total volume of natural gas combusted in the project plant (m 3 ) in year(s) y COEF NG,y : is the CO 2 emission coefficient (tco 2 /m 3 ) in year(s) for natural gas and is obtained as: COEF NG,y = ΣNCV y * EFCO2 NG,y * OXID NG

27 Joint Implementation Supervisory Committee page 27 Where: NCV y : is the net calorific value (energy content) per volume unit of natural gas in year y (GJ/m 3 ) as determined from the fuel supplier, wherever possible, otherwise from local or national data; EFCO2 NG,y : is the CO 2 emission factor per unit of energy of natural gas in year y (tco 2 /GJ) as determined from the fuel supplier, wherever possible, otherwise from local or national data; OXID NG : is the oxidation factor of natural gas For startup fuels, IPCC default calorific values and CO 2 emission factors are acceptable, if local or national estimates are unavailable. D Relevant data necessary for determining the baseline of anthropogenic emissions of greenhouse gases by sources within the project boundary, and how such data will be collected and archived: ID number (Please use numbers to ease crossreferencing to D.2.) Data variable Source of data Data unit Measured (m), calculated (c), estimated (e) For which baseline method(s) must this element be included Recording frequency Proportion of data to be monitored How will the data be archived? (electronic/ paper) Comment 7. EF y 8. EF OM,y Emission factor Emission factor CO 2 emission factor of the grid CO2 Operating Margin emission factor of the grid tco 2 /MWh tco 2 / MWh c Simple OM Yearly 100% Electronic During the crediting period and two years after c Simple OM Yearly 100% Electronic During the crediting period and two years after Calculated as a weighted sum of the OM and BM emission factors Calculated as indicated in the relevant OM baseline method above

28 Joint Implementation Supervisory Committee page EF BM,y 10. F i,y 11. COEF i 12. GEN j/k/n,y Emission factor Fuel quantity Emission factor coefficient Electricity quantity CO2 Build Margin emission factor of the grid Amount of each fossil fuel consumed by each power source/ plant CO 2 emission coefficient of each fuel type i Electricity generation of each power source / plant j, k or n tco 2 / MWh Mass or volume tco 2 / mass or volume unit c BM Yearly 100% Electronic During the crediting period and two years after m Simple OM Yearly 100% Electronic During the crediting period and two years after m Simple OM Yearly 100% Electronic During the crediting period and two years after MWh/a m Simple OM Yearly 100% Electronic During the crediting period and two years after Calculated as [Σi Fi,y*COEFi] / [Σm GENm,y] over recently built power plants defined in the baseline methodology Obtained from the power producers, dispatch centers or latest local statistics Plant or country specific values to calculate COEF. Obtained from the power producers, dispatch centers or latest local statistics.

29 Joint Implementation Supervisory Committee page Plant name Identification of power source / plant for the OM Text e Simple OM Yearly 100% of set of plants Electronic During the crediting period and two years after Identification of plants (j, k, or n) to calculate OM EF 14. Plant name 15.a GEN j/k/l,y IMPORTS Electricity quantity Identification of power source / plant for the BM Electricity imports to the project electricity system Text e BM Yearly 100% of set of plants Electronic During the crediting period and two years after kwh c Simple OM Yearly 100% Electronic During the crediting period and two years after Identification of plants (m) to calculate Build Margin emission factors Obtained from the latest local statistics. If local statistics are not available, IEA statistics are used to determine imports.

30 Joint Implementation Supervisory Committee page b. COEF i,j,y IMPORTS Emission factor coefficient CO 2 emission coefficient of fuels used in connected electricity systems (if imports occur) tco 2 / mass or volum e unit c Simple OM Yearly 100% Electronic During the crediting period and two years after Obtained from the latest local statistics, or IPCC default values 16. EGPJ, y Electricity quantity Electricity generated in the project plant kwh m For setting baseline emissions Yearly 100% Electronic During the crediting period and two years after The total electricity production will be monitored in project 17. HG y Heat quantity Heat generated in the project plant GJ m For setting baseline emissions Yearly 100% Electronic During the crediting period and two years after The total heat production will monitored in project 18. ε baseline,y Energy efficiency Heat generated in in the absence of the project activity m For setting NG consumption in baseline Once a year 100% Electronic During the crediting period and two years after