JOINT IMPLEMENTATION PROJECT DESIGN DOCUMENT FORM Version 01 - in effect as of: 15 June 2006 CONTENTS. Annexes

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1 Joint Implementation Supervisory Committee page 1 JOINT IMPLEMENTATION PROJECT DESIGN DOCUMENT FORM Version 01 - in effect as of: 15 June 2006 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

2 Joint Implementation Supervisory Committee page 2 SECTION A. General description of the project A.1. Title of the project: Low-pressure associated petroleum gas utilization at Enisei Ltd., Usinsk, Komi Republic, Russia Version: 1.0 Date: 15 October 2007 A.2. Description of the project: The project is aimed at utilization of low-pressure associated petroleum gas (APG) and elimination of APG flaring at Zapadno-Synatyskoe (West Synatysk) oil field in Usinsk, Komi Republic, Russia. The project is implemented on the site of booster pump station (BPS) at West Synatysk oil field operated by Enisei Ltd. (See. Fig. А.2-1). Fig. А.2-1. BPS at Zapadno-Synatyskoe (West Synatysk) oil field The BPS serves for crude oil collection from wells and preparation of separator oil. The necessary technological operation performed at the BPS is APG separation from oil via two-stage separation. Currently, APG from the high-pressure separator is totally captured and used. The larger proportion of this gas is directed to the nearby inter-field gas collecting pipeline for further treatment at the existing gas processing plant, while the smaller proportion of associated gas is used for on-site consumption at the BPS. However low-pressure APG after the end separation unit is not recovered but is flared instead. Low-pressure APG accounts for at least 22% of the total APG produced at the oil-field. The project envisages construction of a vapor recovery unit (VRU). Gas from the end separation stage will be fed to the VRU. At the outlet of the unit, two market products will be produced: dry gas and gas condensate. Due to operation of a compressor, which is a part of the VRU, the pressure of dry gas will be sufficient to enable its feeding into the gas collecting pipeline. Gas condensate will be collected and also supplied for further processing, either directly or together with the crude oil. Both dry gas and gas condensate will, ultimately, substitute in the market other fuels with the same or even higher carbon intensity (content). Implementation of the project will make it possible to practically stop APG flaring at the BPS operated by Enisei Ltd. The proportion of APG utilized at Enisei Ltd. will increase up to 99% or even higher.

3 Joint Implementation Supervisory Committee page 3 The project will result in the following: - Reduction of APG flaring by up to 13.5 million m 3 per annum. - Reduction of СО 2 emissions by tonnes per annum on average over five years ( ); - Production of dry gas (up to 13 million m 3 per annum) and gas condensate (around 1000 tonnes per annum); - Improvement of the environment in the locality of the oil field. The equipment of the VRU is now being set up. The company expects the unit to be put into service in normal operating mode by the end of The total actual cost of VRU construction and setup with allowance for the cost of associated equipment, including the cost of installation and certification of instrumentation and control systems, amounts to RUR 24 million (EUR ). The decision to implement the project was made taking into account the possibility to cover the costs and to significantly improve the project profitability by selling achieved reductions of GHG emissions. For this purpose Enisei Ltd. signed Carbon Asset Development Agreement with Camco International on A.3. Project participants: Party involved Party A: Russian Federation (host Party) Party B: EU countries Legal entity project participant (as applicable) Legal entity A1: Private company Enisei Limited Legal entity B1: Private company Camco International Limited Please indicate if the Party involved wishes to be considered as project participant (Yes/No) No No Enisei Ltd. a company with a valid license for use of subsurface resources with the purpose designated as follows: Exploration and production of hydrocarbons at Zapadno-Synatyskoe (West Synatysk) oil field. Enisei Ltd. was established and registered in The company s core business is extraction, treatment and transportation of oil and associated operations at Zapadno-Synatyskoe (West Synatysk) oil field. The company began production testing of Zapadno-Synatyskoe (West Synatysk) oil field in June In 2000, the company produced tonnes of oil. Cumulative production as of January 1, 2006 amounted to tonnes of oil. In 2006, the company produced tonnes of oil. The personnel numbered 732 employees in Camco International Limited is a Jersey based public company listed at AIM in London. Camco International is the world leading carbon asset developer and projects promoter under both joint implementation and clean development mechanism of the Kyoto Protocol. Camco s project portfolio consists of more than 70 projects, generating altogether about 120 Mt CO 2 e of GHG reductions all over the world. Camco operates in Eastern Europe, Africa, China, and Southeast Asia. The company has been actively operating in Russia since 2005.

4 Joint Implementation Supervisory Committee page 4 A.4. Technical description of the project: A.4.1. Location of the project: A Host Party(ies): Russian Federation A Region/State/Province etc.: Komi Republic A City/Town/Community etc.: The Town of Usinsk Komi Republic Fig. A.4-1. The map of the Russian Federation

5 Joint Implementation Supervisory Committee page 5 Usinsk Syktyvkar Fig. A.4-2. The map of Komi Republic Booster pump station Usinsk Fig. A.4-3. BPS at Zapadno-Synatyskoe (West Synatysk) oil field

6 Joint Implementation Supervisory Committee page 6 A Detail of physical location, including information allowing the unique identification of the project (maximum one page): The booster pump station (BPS) owned by Enisei Ltd. is located at Zapadno-Synatyskoe (West Synatysk) oil field which is situated km north of Usinsk along Usinsk-Khariaga motorway. In the vicinity of the BPS lies a gas collecting pipeline owned by LUKOIL Company. This gas pipeline collects APG from production sites of several oil fields, including high-pressure APG produced by Enisei Ltd. The collected APG is transported to Usinsk gas processing plant. The plant processes associated petroleum gas and produces gasoline, as well as liquefied and dry gas for household and industrial needs of Usinsk District and adjacent territories. The pipeline and the gas processing plant are outside the boundaries of this project. The town of Usinsk and its subordinate territories are located in the northeast of Komi Republic in the basin of the Pechora River and its tributary, the Usa River, approximately 90 km from the Arctic Circle. Usinsk lies 757 km from the city of Syktyvkar, the capital of Komi Republic. The population of Usinsk is about people. At present, Usinsk is one of the leading industrial towns of Komi Republic. Rich oil fields were found near Usinsk. Usinsk is the center of the largest oil-producing region in the Republic where four fifths of the total oil production of the Republic is concentrated. Since the development of oil fields in Usinsk region first started, more than 20 fields of hydrocarbons have been developed and more than 200 million tonnes of oil produced. Geographical latitude: 66 05'; geographic longitude: 57 30'. A.4.2. Technology(ies) to be employed, or measures, operations or actions to be implemented by the project: The project envisages construction of the following complex of facilities at the BPS operated by Enisei Ltd.: - Vapor recovery unit manufactured by OJSC Iskra (Russia); - Shell-and-tube heat exchangers for gas cooling; - Condensate tank for collection of gas separated from condensate; and - Gas and condensate metering station. Flow chart of low-pressure APG processing with output of dry gas and condensate is shown in Fig. А.4-4. After the end separation stage, APG (absolute pressure of 0.11 MPa, temperature of 52 0 С) is directed into the tube space of the condensing heat exchanger (Т-1) where the incoming gas is cooled by artesian water with the temperature of 4 0 С fed to the tube side. After going through the heat exchanger Т-1, gas with the temperature not higher than 25 0 С is fed to the separator C-1, where cooled APG is separated into gas condensate and gas. Gas from the upper part of the separator C-1 is fed to the compressing unit and settled gas condensate is fed to the drain tank Е-1 of the condensate collection and degassing unit through electric bolt. Cooled and separated gas is fed to the compressor unit K-1 installed in the block-box. A scrubber CK-1 is installed at the filling line to prevent ingress of liquid into the working part of the compressor. Condensate accumulated in the scrubber is pumped to the drain tank Е-1. Gas compressed to the absolute pressure of 0.4 MPa with the temperature of 75 0 С is fed to the second stage condensing heat exchanger Т-2. After going through the heat exchanger Т-2 gas with the temperature of not higher than 15 0 С is fed to the second stage separator C-2.

7 Joint Implementation Supervisory Committee page 7 Condensate is further separated from gas in the separator C-2. Gas from the separator C-2 is directed to the gathering gas pipeline, and settled gas condensate is fed to the drain tank E-1. Dissolved gas is ultimately removed in the drain tank E-1. Gas from the top of the tank E-1 is directed to the gas vent stack. Gas condensate is pumped by a submersible pump from the tank E-1 to the condensate tank ОГ-200. From this tank condensate is pumped to road tanks. If there is no demand for clean gas condensate, it is planned to be sold mixed with separator oil. Fig. А.4-4. Flow chart of low-pressure APG processing For the sake of safety, the design provided for starting by-pass lines, which enable taking operational measures when any equipment or the entire unit is started, stopped or in any emergency situations. Both in case of emergency and during scheduled maintenance of the equipment, gas feeding to the unit will be discontinued and associated gas will be directed to the existing petroleum gas flare. The general view of the mounted compressor unit of the VRU is shown in Fig. А.4-5. Fig. А.4-5. Compressor unit of VRU

8 Joint Implementation Supervisory Committee page 8 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: Before the project, low-pressure APG from the end separation stage was fed to flaring that resulted in CO2 emissions into the atmosphere. Under the project, low-pressure APG would be utilized in the new VRU to produce dry gas and gas condensate thus avoiding its flaring (except for the cases when the VRU is under repair or in case of emergencies) and CO2 emissions. Dry gas and gas condensate produced under the project from the recovered APG will be further processed to produce fuels that will substitute other existing fuels with the same or even higher carbon intensity. (Transportation, processing and final use of these products are outside the project boundaries). GHG emission reductions can not be achieved without implementation of the JI project, since the project costs are rather high while return on investments is far too low for the oil industry, some 17.6% in the absence of emission trading. Whereas participation in JI makes the project profitability (IRR) three times as high (see Sector B2 for details). Under standard conditions (no JI), Enisei Ltd. could avoid investments in the project and continue flaring of low-pressure APG which is a common practice in Russia, without having any serious obstacles (baseline scenario). It should be noted that currently the company is utilizing up to 78% of APG which is far above the industry average and totally meets the requirements of both federal and local authorities. A Estimated amount of emission reductions over the crediting period: Year Estimate of annual emission reductions in tonnes of CO2 equivalent Total estimated emission reductions over the crediting period (tonnes of CO2 equivalent) Annual average of estimated emission reductions over the crediting period (tonnes of CO2 equivalent) A.5. Project approval by the Parties involved: The letters of approval from the Parties will be received later

9 Joint Implementation Supervisory Committee page 9 SECTION B. Baseline B.1. Description and justification of the baseline chosen: Methodological approach The most appropriate CDM methodology is the approved methodology AM0009/Version 02.1 Recovery and utilization of gas from oil wells that would otherwise be flared, 13 May However the applicability of this methodology does not fully meet the project under consideration (See Table B.1-1). Therefore, wherever possible, the developer uses elements of methodology AM0009, coordinating his approach with the requirements of Decision 9/CMP.1, Appendix B. Everything concerning assessment of emissions is sufficiently described and justified. Table B.1-1. Applicability of AM0009 methodology to the project Applicability criteria of Methodology AM0009 /Version 02.1 Gas at oil wells is recovered and transported in pipelines to a process plant where dry gas, LPG and condensate are produced Energy required for transport and processing of the recovered gas is generated by using the recovered gas The products (dry gas, LPG and condensate) are likely to substitute in the market only the same type of fuels or fuels with a higher carbon content per unit of energy The substitution of fuels due to the project activity is unlikely to lead to an increase of fuel consumption in the respective market In the absence of the project activity, the gas is mainly flared Applicability Applicability is limited Not applicable Applicable Applicable Applicability is limited Comments The project considers only low-pressure APG at the outlet from the end separation unit, which is fed to the VRU located at the same production site. Dry gas and condensate are produced at the VRU. Dry gas mixed with APG from other sources is transported via gathering pipeline to Usinsk gas processing plant. APG might be partially used directly from the gas pipeline at the field power plants. Condensate is supplied to consumers as it is or, which is more likely, in mixture with separator oil. Transportation, processing and final use of dry gas and condensate are excluded from the boundaries of the project as the project owner does not control these processes. However, methane emissions associated with transportation and processing of produced dry gas and condensate are considered as project leakages. The pressure of low-pressure gas at the outlet of the end separation unit is sufficient for its feeding to the VRU. The pressure of dry gas at the outlet of VRU is sufficient for its feeding to the gas collecting pipeline and transportation to the gas processing plant. Grid electricity is consumed for running the VRU compressor. GHG emissions associated with consumed grid electricity are accounted to the project. Dry gas and condensate and/or products obtained from them are likely to substitute fuels with no smaller carbon load (it just might be heavy fuel oil and coal) in the market both in Usinsk region and outside. Additional amount of fuel produced owing to the project is not that large as to cause any decrease of fuel prices for the end users. Thus, the project activity is unlikely to lead to an increase of fuel consumption. Applicable only to low-pressure APG, the entire amount of which would be flared without the project. Highpressure APG has been already used for internal and external consumption since 2002.

10 Joint Implementation Supervisory Committee page 10 Data (quantity and fraction of carbon) is accessible on the products of the gas processing plant and on the gas recovered from other oil exploration facilities in cases where these facilities supply recovered gas to the same gas processing plant Applicability is limited The VRU is fitted with the necessary instrumentation for regular metering and composition analysis of all incoming products at its inlet (low-pressure APG) and outlet (dry gas and gas condensate) during the entire monitoring period under the project. The data regarding quantity and composition of APG supplied into the gas collecting pipeline from other oil fields are outside the control of the project participants. The same is true for gas and oil processing plants, from where dry gas and condensate could be directed for further processing. In addition to the comments given above in Table B.1-1, it is also necessary to consider the following. Theoretically, shortage of low-pressure APG from the end separation stage can be covered by feeding gas from the high-pressure separator to the VRU through the same inlet meter in order to ensure full loading of the VRU compressor. This could lead to exaggerating of GHG emission reductions under the project since without the project, high-pressure APG would be utilized anyway. To avoid this, lowpressure NPG should be separated from and at any time not mixed with high-pressure APG which can hardly be done technologically. Therefore, the decision was made to provide for this by means of methodology applied for calculating of GHG emission reductions. Thus, for the purpose of estimation of GHG emission reductions under the project the amount of lowpressure APG utilized in the new VRU in each year from 2008 through 2012 was limited by setting up and applying the maximum gas fraction designated as f, expressed in per cent and determined by rounding off to the whole number of the average ratio of flared gas to the total amount of APG generated at the oil field over the last three years ( ). Having actual data on the APG balance for this period (See Appendix 2.1), we get the gas fraction f of 24%. With respect to the project, fraction f is stated as a cut-off condition and will be used in monitoring of actual emission reductions. Analysis of the project alternatives and choice of the baseline In principal, low-pressure APG could be treated in the following ways (including project activity as not JI): Alternative 1: Release into the atmosphere at the oil production site (venting); Alternative 2: Flaring at the oil production site; Alternative 3: On-site consumption; Alternative 4: Injection into oil reservoir; Alternative 5: Recovery of dry gas and condensate and their supply to consumers (project activity as not JI). Let us perform more detailed analysis of each alternative. Alternative 1: Release into the atmosphere at the oil production site (venting) This scenario is not acceptable, since safety requirements prohibit free venting of APG into the atmosphere instead of flaring. Thus, Alternative 1 is excluded from further consideration. Alternative 2: Flaring at the oil production site Flaring of low-pressure APG from the end separation stage at the production site of Enisei Ltd. is common practice. At present, there is no rigid regulatory framework in Russia, which would prohibit APG flaring. The levels of penalties for APG flaring are several times lower than those in other developed oil producing countries and therefore, companies do not incur any significant costs in comparison with the income realized from oil sales. Neither this nor dumping state prices for APG in any way encourages subsoil users to utilize this hydrocarbon material.

11 Joint Implementation Supervisory Committee page 11 In 2002, Enisei Ltd. implemented measures to provide for feeding of high-pressure APG to the gas collecting pipeline which belongs to LUKOIL. This increased the level of APG utilization at Zapadno- Synatyskoe (West Synatysk) oil field up to 78% of the total APG produced. This is much higher than the industry average in Komi Republic and in Russia at large and satisfies both federal and local authorities. Such a high level of APG utilization is definitely not a common practice among Russian oil producing companies because of significant barriers and lack of appropriate incentives. As a rule, it is by far more economically efficient for Russian oil companies to invest in increasing of oil production rather than in developing of non-core activities. Thus, Enisei Ltd. could have carried on with the existing practice of low-pressure APG flaring without any serious obstacles, and therefore Alternative 2 is considered as the most likely baseline scenario. Alternative 3: On-site consumption Consumption of APG for internal needs of Enisei Ltd. can only cover operation of process furnaces and heating requirements of personnel facilities at the field, which altogether accounts for 6 to 8% of the total APG produced. For these purposes high-pressure gas is used. The project does not lead to any increase of APG consumption at the field, therefore both in the baseline and in the project scenario this item of APG balance remains unchanged. Thus, Alternative 3 is excluded from further consideration. Alternative 4: Injection into oil reservoir APG injection back into the oil reservoir has not been ever considered by the company management and is unlikely to be considered in future; therefore Alternative 4 is excluded from further consideration. Alternative 5: Recovery of dry gas and condensate and their supply to consumers (project activity as not JI) The project would enable the output of useful fuel products: dry gas and gas condensate, at Zapadno- Synatyskoe (West Synatysk) oil field. However, the investment analysis has shown low profitability of such a project as not JI with IRR being only 17.6% (See Section B.2). There are at least two main reasons for that: - APG prices in Russia are set by the government and are much lower than the prices for other hydrocarbon energy resources; - Though the price for gas condensate is rather high, its production under the project is marginal (some tonnes per annum) making its marketing and sale difficult, for it s really hard to find the buyers for small consignments of pure condensate. Furthermore, the company would have to certify pure condensate in order to sell it in the market, which is associated with additional costs that might fail to be covered due to the small amounts of produced condensate. Under the circumstances, the company will most likely supply condensate in mixture with separator oil, in which case income would drop significantly. Taking into the account the above mentioned, the enterprise would hardly implement the project under business-as-usual. Thus, Alternative 5 is unlikely to be the baseline scenario. Summarizing results of the above analysis of the alternatives, the most likely alternative was chosen as the baseline, namely Alternative 2, which envisages continuation of the current practice of low-pressure APG flaring.

12 Joint Implementation Supervisory Committee page 12 Key factors which determine GHG emissions According to the methodology AM0009, calculation of the baseline GHG emissions assumes that the entire volume of APG fed to the VRU would have been otherwise flared and all carbon contained in APG would be oxidized to carbon dioxide. In practice, however, flaring is often conducted under suboptimal combustion conditions and a part of APG is released into the atmosphere as methane and other volatile gases. Despite that, in order to avoid difficulties and additional costs associated with regular measurement of the quantity of methane released from flaring for the purpose of determining baseline emissions for the project, it is assumed that all carbon in APG is converted into carbon dioxide. This is a conservative assumption, as accounting of methane emissions from flaring would definitely increase baseline emissions. Key factors, which determine the projected level of baseline GHG emissions, are considered below. The project emissions are marginal and all factors which determine these emissions are considered in Section E. Oil and APG production Irrespective of the project implementation, the enterprise plans to keep to the design levels of oil production. APG production is proportional to the oil production. Gas-oil ratio is practically a constant value. Table B.1-2 below shows Enisei Ltd. s design oil and APG production at Zapadno-Synatyskoe (West Synatysk) oil field for the period Peak oil rate at the oil field was met in 2006; oil production will thereafter tend to fall. Table B.1-2. Design levels of oil and APG production y, year Oil production, 000 t APG production V,, million m 3 R y APG volume which without the project would be flared At present, up to 70% of all APG produced is fed to the gas pipeline owned by LUKOIL. Between 6 and 8% of APG is used for own needs of the oil field. Leaks are negligibly small and do not exceed 0.05%. The remaining gas (low-pressure gas from the end separator) is flared. According to the APG balance for the period from 2004 till 2006 provided by Enisei Ltd., the volume of APG flared accounted for % of its total production. Following the conservative approach, the lower value was assumed for projection purposes, namely 22.4%. Table B.1-3 below shows projected volumes of APG, which would be flared without the project. Table B.1-3. Projected volume of APG, which would be flared without the project Level of APG utilization in the VRU y, year Volume of flared APG without the project, million m Vapor recovery unit would be capable of utilizing the entire projected volume of low-pressure APG. However it has to undergo scheduled repairs, which may take up to 2 weeks per year. During this time all

13 Joint Implementation Supervisory Committee page 13 low-pressure APG will be flared. Thus, it is assumed that the VRU will utilize up to 96% of APG, which without the project would have been flared. It is the volume of APG utilization under the project (See Table B.1-4) that was used for calculation of СО 2 emissions from flaring under the baseline scenario, which is in compliance with AM0009 methodology. Table B.1-4. Volume of APG utilization in VRU y, year Volume of APG utilization in VRU V,, million m 3 A y The volume of utilized associated gas will be specified during monitoring (point А in Fig. B.3-2). In order to have a full picture, the total balance of APG with projections up to 2012 is presented in Annex 2.1. Volumes of APG under various balance items were calculated as per proportions identical to the year 2005 (the most conservative option). The project does not have any impact upon the levels and the structure of high-pressure APG utilization and will not lead to increase of APG consumption for own needs of the oil field. Composition of gas after the end separation stage APG composition by volume after the first separation stage (gas which is fed to the VRU under the project or to the flare under the baseline) was determined by means of chromatographic measurements at the stage of project development (See Table B.1-5). Gas composition should not undergo any major changes up to the end of the field development period; however it will be checked on a regular basis during monitoring. Table B.1-5. Low-pressure gas composition by volume Gas component Volume fraction, % Methane Ethane Propane Isobutane 6.24 Butane Isopentane 1.73 Pentane 1.21 Hexane+higher hydrocarbon 0.29 Nitrogen 1.40 Carbon dioxide 0.67 Hydrogen sulphide 0.00 Oxygen 0.90 Total V, A y

14 Joint Implementation Supervisory Committee page 14 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: (a) Description of the baseline scenario The baseline scenario envisages continuation of the current situation at the oil field operated by Enisei Ltd. Low-pressure APG after the end separation unit will continue to be fed for flaring. (b) Description of the project scenario Under the project, low-pressure APG after the end separation stage will be fed in a new vapor recovery unit (VRU) that will be installed on the site of booster pump station operated by Enisei Ltd. This will enable to almost completely avoid APG flaring on the site of BPS operated by Enisei Ltd. At the outlet of the VRU dry gas and gas condensate will be obtained. Dry gas will be compressed and fed into the existing collecting gas pipeline owned by LUKOIL. Gas condensate will be also collected and fed for further processing both as it is or, which is more likely, in mixture with separator oil. In the market, dry gas and gas condensate will substitute, directly or through further processing, other fuels with the same or even higher carbon load. (c) Additionality To prove additionality of the project against the baseline, investment, barriers and common practice analyses have been applied. Also see the analysis of the project alternatives given in Section B.1. Investment analysis The main economic parameters were compared for the two project implementation options: (I) project as not JI and (II) project as JI. According to the data provided by Enisei Ltd., the total project costs amount to RUR million (which is approximately EUR ). Selling price for ERU ( ) is assumed 5 EUR/tonne of СО 2 which is the lower threshold of the projected price range of 5-20 EUR/tonne of СО 2 for the period The horizon period of the analysis is limited by the year The hurdle rate of return is assumed equal to 20%, which is conservative. According to the research Russian Economy in Trends and Prospects Section 3. Table 27 1, the return on investments into a typical oil field in East Siberia under the current taxation system and with the price for Urals oil being 60 USD/barrel, is equal to 22.2%. It should be also noted that: (a) climatic conditions in East Siberia are more severe and the infrastructure is less developed as compared to Komi Republic; (b) oil price today is higher than 70 USD/barrel; and (c) APG utilization project brings about additional risks as compared to usual projects related to oil and gas production and processing. As a result of the project, it would be possible to realize a certain income from selling dry gas and condensate and to avoid marginal penalties for APG flaring. However, there will be some electricity costs and expenses associated with the unit maintenance and repair. In the course of run-in tests of the VRU at Zapadno-Synatyskoe (West Synatysk) oil field it was identified that the actual production of stable condensate from associated gas as compared to the maximum theoretically possible output (hydrocarbons С 5 and higher) will amount to around 65%. The remaining proportion of condensate is carried with the gas and can not be recovered by the VRU. For the purposes of conservative approach, the indicated factor was assumed equal to a higher value of 80%. 1

15 Joint Implementation Supervisory Committee page 15 Considering this, the estimated sales of condensate and dry gas in 2008 will amount to tonnes and million m 3, respectively. In the future, due to gradual depletion of the oil field, oil production and proportionally, APG production will be falling. This in its turn will lead to decrease of the VRU output of dry gas and condensate and to drop of revenues from sales of these products. The detailed investment analysis can not be disclosed to the general public but is accessible to JI project participants, as well as to auditing organizations. Results of NPV and IRR calculation for the two implementation options are given in Table В.2-1 below. As it shows, the project implementation as not JI generates negative NPV, and IRR is less than 20%, whereas additional income from sales of emission reductions (even at 5 EUR/tonne rate) improves the project profitability by more than three times: NPV = Euro, IRR = 65.1% > 20%. Table B.2-1. Investments, NPV and IRR Data name Unit Project activity as not JI Project activity as JI Investments EUR NPV EUR IRR % Thus, project implementation within the framework of business-as-usual is not profitable for the oil company, whereas participation in JI mechanism offsets all project costs and potential risks. In our opinion, with such well-marked difference in economic parameters of the two implementation options, there is no need to undertake sensitivity analysis. It is clear that project as JI option will withstand serious changes of impacting factors (i.e. investment and operational costs, output and price of dry gas and gas condensate), whereas project as not JI will appear to be completely unviable. Barrier analysis Implementation of the project faces following substantial barriers: Operational barrier Enisei Ltd. has never built and/or operated any APG processing facilities at all; therefore there is a risk associated with the lack of VRU operation experience. The first tests revealed some problems with elevated vibration of the compressing unit. Commercial barrier Because of the small amount of gas condensate recovered from APG in VRU (no more than tonnes per annum) the company would face certain marketing barriers as it would be difficult to sell small consignments of pure condensate in the market. Furthermore, the company will have to obtain a quality certificate in order to sell pure condensate in the market, and this incurs significant additional costs which could hardly be justified on such small amount of product. Therefore Enisei Ltd. will most likely have to sell gas condensate in mixture with separator oil which will result in yet lower gross sales as the selling price of crude oil is much lower than that of condensate. Common practice analysis The project is not common practice in Russia so far. According to different estimations, the total of billion m 3 of APG per year is flared in Russia due to the lack of infrastructure, regulations and real economic incentives. Even in Komi Republic, which has relatively well developed infrastructure (APG collecting pipelines, gas processing plants, etc.) for APG collection and processing, about 730 million m 3 of APG was flared in 2006 while the utilization rate amounted to 60%. The APG utilization rate in Russia on the whole is even lower.

16 Joint Implementation Supervisory Committee page 16 Furthermore one should note that normally, only high-pressure APG is utilized (provided that external infrastructure is available) while low-pressure APG continues to be flared. The point is that (a) output of high-pressure APG is several times higher than that of low-pressure APG, and (b) feeding of highpressure APG into the pipeline is much easier; it does not require installation of compressors and is not associated with additional power use at the oil field which is not the case for low-pressure APG. In general, utilization of APG, especially of its low-pressure stream, does not bring much benefit to oil companies because of its small volumes, relatively low tariffs for APG, and because penalties for flaring are still negligible compared to revenues from oil sales. With the surging oil prices it is by far more profitable to invest into increasing of oil production and processing rather than in utilization of APG. On the part of the state authorities there are currently no rigid requirements regarding utilization of APG though a serious concern has been recently expressed at the very high level. Even if the government makes the requirements stricter in the short term, oil companies will first of all attempt to utilize their high-pressure APG, while utilization of low-pressure APG will be apparently put on the back burner. Moreover, by 2012, the average APG utilization rate for the industry is unlikely to reach the level which has already been achieved by Enisei Ltd. prior to the project (78%). On the other hand, prohibitive administrative measures could hardly force oil companies to utilize the entire volume of APG. Nothing but a major extra incentive can only encourage Russian companies to undertake steps towards increasing their APG utilization rates. One of the options is extra income from selling ERUs, generated through implementation of JI projects aimed at utilization of APG now flared. As shown above, project profitability (in terms of IRR) in this case may increase several times. Russia ratified Kyoto Protocol in 2004; it was then that a number of Russian companies began to think more about seizing the ripe opportunity to implement their projects. Enisei Ltd. was among the first Russian oil producing companies who took this opportunity seriously and considered JI mechanism for its project aimed at recovery of low-pressure APG which is the last and the least (22%) part of APG produced at the oil field thus increasing the APG utilization rate at Enisei Ltd. production site up to 99%. On Enisei Ltd. entered into a Carbon Asset Development Agreement with Camco International Ltd. who is a world recognized carbon asset developer. From our point of view, the above stated reasons are sufficient to demonstrate that the GHG emission reductions achieved through JI project implementation are additional to any that would otherwise occur.

17 Joint Implementation Supervisory Committee page 17 B.3. Description of how the definition of the project boundary is applied to the project: Table B.3-1. shows which GHG emission sources are included in the project boundaries and which are excluded from them. Fig. B.3-1 and Fig. B.3-2 present the principal components, boundaries and the main GHG sources for the baseline and project. Table B.3-1. Sources of emissions included in or excluded from consideration Baseline Project Activity Leakages Source Gas Included? Justification / Explanation CO 2 Yes Main source of emissions Gas flaring CH 4 No Considered negligible. Conservative N 2 O No Considered negligible. Conservative Grid electricity consumption for CO 2 Yes Main source of emissions VRU needs CH 4 No Considered negligible Leaks during gas processing in VRU Gas transportation and processing (both in VRU and outside it) Condensate transportation and processing N 2 O No Considered negligible CO 2 Yes Main source of emissions CH 4 No Is considered in evaluation of overall leakages connected with gas processing and transportation N 2 O No Considered negligible CO 2 No Considered negligible CH 4 Yes Main leakage N 2 O No Considered negligible CO 2 No Considered negligible CH 4 No Considered negligible N 2 O No Considered negligible Other oil fields Gathering line Gas transportation Gas processing plant High-pressure APG High-pressure separator On-site consumption Low-pressure separator Low-pressure APG Flaring CO2 Oil Ga products Oil production wells Petroleum products Oil Refining Oil transportation Main GHG emissions Booster pump station Baseline boundary Fig. B.3-1. Principal components, boundaries and the main GHG source of the baseline

18 Joint Implementation Supervisory Committee page 18 Other oil fields Gathering line CO2 Outside power producers Gas transportation Gas processing plant High-pressure APG On-site consumption Dry gas CO2 CH4 Leaks B Electricity Vapour recovery unit Low-pressure APG A B Condensate Gas products High-pressure separator Low-pressure separator Oil Oil production wells Petroleum products Oil Refining Oil transportation Booster pump station Main GHG emissions Project boundary Fig. B.3-2. Principal components, boundaries and the main GHG sources of the project 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 BL setting 08 October 2007 BL was developed by Camco International Limited Contact person: Dmitry Voevodkin dmitry.voevodkin@camco-international.com

19 Joint Implementation Supervisory Committee page 19 SECTION C. Duration of the project / crediting period C.1. Starting date of the project: 1 January 2008 (commissioning of equipment in the normal operation mode) C.2. Expected operational lifetime of the project: 20 years/240 months C.3. Length of the crediting period: 5 years/60 months (from the 1st January 2008 to the 31st December 2012)

20 Joint Implementation Supervisory Committee page 20 SECTION D. Monitoring plan D.1. Description of monitoring plan chosen: Monitoring is based on the approved methodology AM0009/Version Recovery and utilization of gas from oil wells that would otherwise be flared. This methodology is applicable to this project with a number of necessary changes justified in Section B.1-1. Fig. B.3-2. shows points A, B I и B II where quantity and composition of low-pressure APG, dry gas and condensate will be measured respectively. Besides VRU compressor operation time and APG annual resource will be fixed. D.1.1. Option 1 Monitoring of the emissions in the project scenario and the baseline scenario: ID number (Please use numbers to ease cross-referencing to D.2.) 1. V A, y 2. w carbon, A, y 3. V B I, y 4. w I carbon, B, y D Data to be collected in order to monitor emissions from the project, and how these data will be archived: Data variable Source of data Data unit Measured (m), Recording Proportion of calculated (c), frequency data to be estimated (e) monitored Volume of lowpressure APG at the inlet of VRU (point A at Fig. B.3-2.) Composition of low-pressure APG at the inlet of VRU (point A at Fig. B.3-2.) Volume of dry gas (point B I at Fig. B.3-2.) Composition of dry gas (point B I at Fig. B.3-2.) Reporting data on VRU operation Reports on the analysis results Reporting data on VRU operation Reports on the analysis results m 3 m Continuously 100% kg/m 3 m Monthly 100% m 3 m Continuously 100% kg/m 3 m Monthly 100% How will the data be archived? (electronic/ paper) Electronic and paper Electronic and paper Electronic and paper Electronic and paper Comment Measured using volumetric flowmeter Determined using gas chromatograph Measured using volumetric flowmeter Determined using gas chromatograph

21 Joint Implementation Supervisory Committee page Volume of V condensate (point B II, y B II at Fig. B.3-2.) Density of 6. condensate ρ B II,y (point B II at Fig. B.3-2.) 7. w II carbon, B, y 8. T VRU, y Composition of condensate (point B II at Fig. B.3-2.) Operation time of VRU Reporting data on VRU operation Reports on the analysis results Reports on the analysis results m 3 m Continuously 100% kg/m 3 m Quarterly 100% kg/kg m Quarterly 100% Operating log hour m Annually 100% Electronic and paper Electronic and paper Electronic and paper Electronic and paper Measured using volumetric flowmeter Determined be measuring sample mass and volume Determined according to the agreement with a specialized company Compressor start and shutdown time is recorded D Description of formulae used to estimate project emissions (for each gas, source etc.; emissions in units of CO 2 equivalent): Project GHG emissions in year y, t СО 2 -e.: PE y PECO2, grid, y + PECO2, VRU, y =, (D.1-1) where PE CO2, grid, y is CO 2 emissions associated with grid electricity consumption by the VRU over a year y, t СО 2 ; PE CO2, VRU, y is CO 2 emissions from leaks during recovery and processing at the VRU over a year y, t СО 2. The amount of CO 2 is determined basing on the carbon balance between points А, B I and B II at Fig. B.3-2 with the assumption that all leaked carbon is oxidized to СО ,, =, 2,, 10 CO grid y ECVRU y EFCO grid y PE, (D.1-2) where EC, is the estimate of electricity consumption by VRU over a year y, MWh; VRU y EF CO2, grid, y is СО 2 emission factor for grid electricity over a year y, kg CO 2 /MWh. According to Operational Guidelines for Project Design Documents of Joint Implementation Projects. Volume 1. General guidelines. Version 2.3. Ministry of Economic Affairs of the Netherlands. May

22 Joint Implementation Supervisory Committee page , emission factor for grid electricity in Russia varies over years as follows: EF CO2, grid, 2008 = 565 kg CO 2 /MWh, EF CO2, grid, 2009 = 557 kg CO 2 /MWh, EF CO2, grid, 2010 = 550 kg CO 2 /MWh, EF CO2, grid, 2011 = 542 kg CO 2 /MWh, EF CO2, grid, 2012 = 534 kg CO 2 /MWh. 3, =, 10 VRU y NVRU TVRU y EC, (D.1-3) where N is power consumption by VRU, kw. According to the project data total power consumption by VRU equipment is N = 120 kw. VRU T, is VRU operation time over a year y, hour. VRU y VRU 44 3 ( mcarbon, A, y m I m II ) PE CO2, VRU, y = 10, (D.1-4) carbon, B, y carbon, B, y 12 where m carbon, A, y is the quantity of carbon in recovered gas at the inlet into the VRU at point A (Fig. B.3-2) over a year y, kg; m I carbon B, y m II carbon B, y m carbon, A, y VA, y wcarbon, A, y, is the quantity of carbon in dry gas leaving the VRU at point B I (Fig. B.3-2) over a year y, kg; is the quantity of carbon in condensate leaving the VRU at point B II (Fig. B.3-2) over a year y, kg., =, (D.1-5) where V A, y is the volume of recovered gas at point A (Fig. B.3-2) over a year y, m 3 w carbon A, y, is the average content of carbon in recovered gas at point A (Fig. B.3-2) over a year y, kg/m 3. m I V I w I carbon, B, y B, y carbon, B, y where B I y =, (D.1-6) V, is the volume of dry gas at point B I (Fig. B.3-2) over a year y, m 3 w I carbon B, y m II carbon, B, y B, y B, y carbon, B, y where is the average content of carbon in dry gas at point B I (Fig. B.3-2) over a year y, kg/m 3., = V II ρ II w II, (D.1-7) V, is the volume of condensate at point B II (Fig. B.3-2) over a year y, m 3 ; B II y ρ is the average density of condensate at point B II (Fig. B.3-2) over a year y, kg/m 3 ; B II,y w II carbon B, y, is the average content of carbon in condensate at point B II (Fig. B.3-2) over a year y, kg/kg.

23 Joint Implementation Supervisory Committee page 23 It should be noted that in case of emergency and/or repair work at the VRU feeding of low-pressure gas to the unit will be stopped and gas will be directed to the existing flare bypassing any flow meters at the VRU. Methane emissions caused by emergencies during gas transportation and processing outside the project boundaries are taken into account indirectly as a part of the total methane emissions during gas transportation and processing.

24 Joint Implementation Supervisory Committee page 24 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) Recording frequency Proportion of data to be monitored How will the data be archived? (electronic/ paper) Comment 9. V R, y APG production (resource) Reporting data on APG balance Data ID 1 and 2 specified in D are also necessary for calculations. m 3 m Annually 100% Electronic and paper Determined using gas-oil ratio D Description of formulae used to estimate baseline emissions (for each gas, source etc.; emissions in units of CO 2 equivalent): Baseline GHG emissions taking into account the cut-off condition (see Section B.1) over a year y, t СО 2 -e.: VA, y 44 3 If 100 f, then BE y = VA, y wcarbon, A, y 10, (D.1-8) V 12 R, y If VA, y 100 > f, then V R, y f 44 3 BE y = VR, y wcarbon, A, y 10, (D.1-9) where f is maximum gas fraction of the total APG resource at the enterprise, which is fed to the VRU. This fraction is stated as the cut-off condition and is assumed equal to f = 24% according to the actual data on APG balance at the enterprise for D Option 2 Direct monitoring of emission reductions from the project (values should be consistent with those in section E.): This option is not applied to the monitoring of this project.

25 Joint Implementation Supervisory Committee page 25 ID number (Please use numbers to ease crossreferencing to D.2.) D Data to be collected in order to monitor emission reductions from the project, and how these data will be archived: Data variable Source of data Data unit Measured (m), Recording Proportion of Comment calculated (c), frequency data to be estimated (e) monitored How will the data be archived? (electronic/ paper) D Description of formulae used to calculate emission reductions from the project (for each gas, source etc.; emissions/emission reductions in units of CO 2 equivalent): D.1.3. Treatment of leakage in the monitoring plan: Methane emissions from gas transportation and processing both at the VRU and outside are considerable leakages which are subject to regular assessment during the project monitoring. The leakages are referred to the total volume of gas fed to the VRU (point А at Figure B.3-2) and are determined using knowingly conservative emission factors recommended for Tier 1 in 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, Table Leakages estimated this way indirectly include methane emissions from possible emergencies outside the project boundaries. ID number (Please use numbers to ease crossreferencing to D.2.) D If applicable, please describe the data and information that will be collected in order to monitor leakage effects of the project: Data variable Source of data Data unit Measured (m), Recording Proportion of Comment calculated (c), frequency data to be estimated (e) monitored How will the data be archived? (electronic/ paper) D 1 value required for calculations is specified in D.1.1.1