ࡱ> XZY` Jdbjbjss g?CM*(*(*(*(...$/PnB|/ʣL(>>: $hY|.JX*(*(>Z*(>Z.<X-. UV(uP.("":N^///Cr$.///r///*(*(*(*(*(*(  Approved baseline methodology AM0014 Natural gas-based package cogeneration Source This methodology is based on the MGM natural gas-based package cogeneration project, Chile, whose baseline study, monitoring and verification plan and project design document were prepared by MGM International. For more information regarding the proposal and its consideration by the Executive Board please refer to case NM0018-rev: MGM baseline methodology Natural Gas-Based Package cogeneration Project on  HYPERLINK "http://cdm.unfccc.int/methodologies/approved" http://cdm.unfccc.int/methodologies/approved Selected approach from paragraph 48 of the CDM modalities and procedures Existing actual or historical emissions as applicable. Applicability This methodology is applicable to natural gas-based cogeneration projects under the following conditions: The cogeneration system is a third party cogeneration systems, i.e. not own or operated by the consuming facility that receives the project heat and electricity; OR the cogeneration system is a self-owned system, owned by the industrial user that receives the project heat and electricity; The cogeneration system provides all or a part of the electricity and or heat demand of the consuming facility; No excess electricity is supplied to the power grid and no excess heat from the cogeneration system is provided to another user. This baseline methodology shall be used in conjunction with the approved monitoring methodology AM0014 (Natural gas-based package cogeneration). Project activity The project activity encompasses the installation of a package cogeneration system whose input is natural gas from the gas pipeline, and whose outputs are electricity and heat supplied to an industry with demand for heat and electricity. The owner and operator of the cogeneration system is different from that of the industry that purchases heat and electricity from the system. Leakage The principal sources of leakage in the sense of emissions of GHG emissions outside the project boundary and attributable to the CDM project are the emission of methane from natural gas production and pipeline leakage, associated with gas consumption of cogeneration system. Baseline Baseline emissions are those emissions that those associated with the production of heat and electricity that are offset by the output of the cogeneration system. Baseline emissions comprise five components: CO2 from combustion. CO2 emissions corresponding to the combustion of natural gas that would have been used if the cogeneration system did not provide heat to the factory. CH4 from combustion. CH4 emissions corresponding to the combustion of natural gas that would have been used if the cogeneration system did not provide heat to the factory. N2O from combustion. N2O emissions corresponding to the combustion of natural gas that would have been used if the cogeneration system did not provide heat to the factory. CH4 leaks. CH4 emissions from natural gas production and leaks in the transport and distribution pipeline supplying the factory and leaks in the gas distribution piping within the factory, associated with the natural gas consumption identified in item (a) above. CO2 from electricity generation. CO2 emissions associated with the electricity that would have to be purchased from the power grid if the cogeneration system did not provide electricity to the factory. The baseline emissions for the first four items are proportional to the natural gas consumption in the factory that is offset by heat supplied by the cogeneration system. Each can be represented as the product of an emissions factor and an energy consumption, which depends on the heat output of the cogeneration system. The consumption of natural gas avoided in the baseline for the supply of heat is determined as follows: This is estimated on the basis of the heat output rate of the cogeneration system (CHOR) and an estimate of annual operating hours (AOH) of the cogeneration system. The formula is described below: The value of CHOR may be determined from the specifications of the cogeneration system. A value of AOH should be determined from an engineering study of the proposed cogeneration system. Once the boiler energy consumption has been quantified, the four GHG emissions components (a to d, above) can be determined, as indicated below. Baseline CO2 emissions from natural gas combustion for heat supply to plant A value of EFNG needs to be estimated from the following data sources. The numbers indicate a hierarchy in data to be used, with #1 being the best. If #1 data are not available, #2 data should be chosen. If these are not available,#3 data should be chosen. National GHG inventory IPCC, fuel type and technology specific IPCC, near fuel type and technology Baseline methane emissions from natural gas combustion for heat supply to plant The value of MEF needs to be estimated from the following data sources. The numbers indicate a hierarchy in data to be used, with #1 being the best. If #1 data are not available, #2 data should be chosen. IPCC, fuel type and technology specific IPCC, near fuel type and technology Baseline nitrous oxide emissions from natural gas combustion for heat supply to plant  The value of NEF needs to be estimated the following data sources. The numbers indicate a hierarchy in data to be used, with #1 being the best. If #1 data are not available, #2 data should be chosen. IPCC, fuel type and technology specific IPCC, near fuel type and technology Baseline methane emissions from natural gas production and pipeline leaks in the transport and distribution The value of MLR needs to be estimated from the following data sources. The numbers indicate a hierarchy in data to be used, with #1 being the best. If #1 data are not available, #2 data should be chosen. National estimates (if available) IPCC estimates of fugitive emissions from oil and natural gas activities. Baseline emissions of CO2 from electricity supply to industrial plant, that is offset by electricity supplied from cogeneration system The final item of GHG emissions in the baseline arises from electricity, corresponding to the emissions avoided at the power plants supplying the public grid, including transmission and distribution losses. The relevant formula is described below:  The actual baseline emissions are determined by monitoring cogeneration electricity output (CEO) and calculating BEelec. For an a priori estimation of the baseline CO2 emissions for electricity supply to the plant, CEO is determined by the cogeneration electric power output (CPO) and annual operating hours (AOH), in a manner similar to Eq. (3.2) for heat output, and is described below.  To estimate BEFelec, the CO2 emission factor for electricity supply, users of this methodology shall refer to the Consolidated Baseline Methodology for Zero-emissions Grid-Connected Electricity Generation from Renewable Sources where different ways of determining CO2 emission factors for electricity supply from the grid are provided, or to the Simplified Methodology for Small-scale CDM Project activities (in case electricity displaced is less than or equal to 15 MW equivalent). Total baseline emissions are given by the sum of the components analyzed above:  EMBED Equation.3  (3.15) Emission Reductions Emission reductions are calculated as the difference between baseline and project emissions, taking into account any adjustments for leakage: Project emissions are those associated with natural gas consumption by the cogeneration system, including CO2, CH4 and N2O emissions from natural gas combustion and CH4 emissions from natural gas production and pipeline leakage, associated with the gas consumption of the cogeneration system. Additionality First likely alternative baseline scenarios are described: Industrial plant continues to operate with equipment replacement as needed with no change in equipment efficiency (The frozen-efficiency scenario). Industrial plant continues to operate with improved efficiency new equipment at the time of equipment replacement. The efficiency of boiler(s) is upgraded immediately. The heat and or electricity demand of the industrial plant is reduced through improvements in end-use efficiency. Installation of a cogeneration system owned by the industrial plant. Installation of a package cogeneration system owned by a company other than the industrial plant (The proposed project). Installation of a cogeneration system by a third party. Three Four additionality tests are applied. The first two tests are applicable to any cogeneration ownership scenario. The third test is specific to the package cogeneration case where the cogeneration system is owned by a party other than the industry using the heat and electricity from the system. All three tests shall be passed in order for the project activity to be additional. Are there technological barriers to cogeneration in the country? Additionality test 1 is applied by following the flow chart below. A low market share of cogeneration means that there is insufficient infrastructure to support installation and maintenance of such systems, acting as a technological barrier to project participants.            2.A Institutional barrier A: Are there institutional barriers to cogeneration in general? Additionality test 2A is applied by following the flow chart below. It should be noted that even if preferential tariffs or other incentives do exist, they may not be sufficient to promote cogeneration. A serious barrier may be present, especially in deregulated power systems. All electricity users may have to pay the maximum demand charge for the whole year. Thus, when the cogeneration system is not operating (due to routine maintenance or forced outage), the user of electricity would have to purchase the electricity from the power grid. While this period may be small, the purchase may involve paying for the power demand (kW) for the whole year. This is a significant penalty for users of cogeneration systems.           If institutional barriers are not present, but there are no specific incentives to cogeneration, then the test indicated is inconclusive with respect to institutional barrier A. Other barriers (such as technological barrier or institutional barrier B) will need to be considered to determine additionality. 2B. Institutional barrier for ESCOsB: Are there institutional barriers to the package cogeneration operational context? In other words, is there enough experience in which one company installs a cogeneration system at the location of a separate energy user? The traditional practice is for an industrial user to meet their electricity and natural gas demand by purchases from power and gas companies respectively. In a packaged cogeneration system, the institutional arrangement is very different. In this case, the project developer invests in and installs the cogeneration system at the industrial user site, and provides electricity and heat to that user. This institutional arrangement requires project developer to have special management resources and organizational capacity, and for the industrial energy user to accept this arrangement. Where such experience is lacking, promoting the new arrangement involves a significant institutional barrier. Additionality test 2B is applied by following the flow chart below.          2C. Institutional barriers for Industrial Users: Are there institutional barriers to the package cogeneration operational context? In other words is there enough experience in which an industrial user can install and operate a cogeneration system at its plant premises? The traditional practice is for an industrial user to meet their electricity and natural gas demand by purchases from power and gas plants respectively. In this case, the industrial user, installs and operates the cogeneration system for use at its own site. This arrangement requires the industrial user to have specific expertise and knowledge of cogeneration systems. Where such experience is lacking, promoting the new arrangement involves a significant institutional barrier. Additionality test 2C is applied by the following flow chart below:  If the above additionality tests determine that a package cogeneration system is additional with respect to scenarios where no cogeneration system, scenarios 1 to 4 remain as baseline options. The selection cannot be made without a substantial analysis. Therefore, a conservative approach is taken by assuming a high value for eb in Eq. 3.2 to calculate the baseline emissions. This assumption implies reduced natural gas consumption in the baseline, and therefore reduced emission reductions compared to option 1-3. Option 4 is discounted for by determining the baseline ex-post on the basis of actual heat and electricity of the industrial plant. Approved monitoring methodology AM0014 Natural gas-based package cogeneration Source This methodology is based on the MGM Natural gas-based package cogeneration Project, Chile, whose baseline study, monitoring and verification plan and project design document were prepared by MGM International. For more information regarding the proposal and its consideration by the Executive Board please refer to case NM0018-rev: MGM baseline methodology Natural Gas-Based Package cogeneration Project on  HYPERLINK "http://cdm.unfccc.int/methodologies/approved" http://cdm.unfccc.int/methodologies/approved Applicability This methodology is applicable to natural gas-based cogeneration projects under the following conditions: The cogeneration system is a third party cogeneration systems, i.e. not own or operated by the consuming facility that receives the project heat and electricity, OR the cogeneration system is a self-owned system, owned by the industrial user that receives the project heat and electricity; The cogeneration system provides all or a part of the electricity and or heat demand of the consuming facility; No excess electricity is supplied to the power grid and no excess heat from the cogeneration system is provided to another user. This monitoring methodology shall be used in conjunction with the approved baseline methodology AM0014 (Natural gas-based package cogeneration). Monitoring Methodology The monitoring methodology involves monitoring of the following: The natural gas consumption at the cogeneration system; Heat production at the cogeneration system; Electricity production at the cogeneration system. Project emissions correspond to natural gas combustion by the cogeneration system, and includes the same four components as in the baseline (CO2, CH4 and N2O emissions from combustion) and CH4 emissions from natural gas production and leaks in the transport and distribution pipeline supplying the factory and leaks in the gas distribution piping within the factory, associated with the natural gas consumption. Each of these is proportional to the natural gas consumption in the cogeneration system, which is monitored. Emissions are then calculated as follows: a) CO2 emissions from natural gas combustion in cogeneration system  b) Methane emissions from natural gas combustion in cogeneration system c) Nitrous oxide emissions from natural gas combustion in cogeneration system  d) Methane emissions from natural gas production and pipeline leaks in the transport and distribution of natural gas, including leakage within the industrial plant Total project emissions are given by the sum of the components analyzed above:  EMBED Equation.3  (4.8) Parameters to be monitored ID numberData typeData variableData unitMeasured (m), calculated (c) or estimated (e)Recording frequencyProportion of data to be monitoredHow will the data be archived? (electronic/ paper)For how long is archived data to be kept?Comment1.Volume of natural gas consumedMECNGm3mmonthly100%paper (field record) electronic (spreadsheet)Paper: 1 year, Electronic: 7 years2.Cogeneration electricity supplied to industrial plantMCEOMWhmmonthly100%electronic (spreadsheet)Electronic: 7 years3.Cogeneration heat supplied to industrial plantMCHOGJmmonthly100%electronic (spreadsheet)Paper: 1 year Electronic: 7 years Quality Control (QC) and Quality Assurance (QA) Procedures DataUncertainty level of data (High/Medium/Low)Are QA/QC procedures planned for these data?Outline explanation why QA/QC procedures are or are not being planned.1.LowYesThese data will be used as supporting information to calculate emission reductions by project activity2.LowYesThese data will be used as supporting information to calculate emission reductions by project activity3.LowYesThese data will be used as supporting information to calculate emission reductions by project activity4.LowYesThese data will be used as supporting information to calculate emission reductions by project activity     AM0014 / Version 01 Sectoral Scope: 1 and 4 3 September 2004 PAGE 1 PAGE 9 AM0014/ Version 01 Sectoral Scope: 1 and 4 3 September 2004 Annual baseline natural gas energy consumption for heat supply, ABECNG (GJ/year):  EMBED Equation.3  (3.1) where CAHO = annual heat output from cogeneration system (GJ/year), and eb = industrial boiler efficiency (fraction, lower heating value basis). Annual baseline natural gas energy consumption for heat supply, ABECNG (GJ/year):  EMBED Equation.3  (3.2) where CHOR = cogeneration system heat output rate (GJ/h), AOH = Annual operating hours (h/year), and eb = boiler efficiency (fraction, lower heating value basis) In order to be conservative, a high value of eb is chosen. The methodology proposes a default value of 0.90. Baseline methane emissions from natural gas combustion for heat supply, BEmet comb (tonne CH4/year):  EMBED Equation.3  (3.4) where ABECNG = annual baseline natural gas energy consumption for heat supply (GJ/year), and MEF = methane emission factor for natural gas combustion (kg CH4/TJ, lower heating value basis) In units of carbon dioxide equivalent, BEequiv met comb (tonne CO2 eq/year)  EMBED Equation.3  (3.5) where GWP (CH4) = global warming potential of methane = 21 Baseline nitrous oxide emissions from natural gas combustion for heat supply, EMBED Equation.3 (tonne N2O/year):  EMBED Equation.3  (3.6) where ABECNG = annual baseline natural gas energy consumption for heat supply (GJ/year), and NEF = nitrous oxide emission factor for natural gas combustion (kg N2O/TJ, lower heating value basis) In units of carbon dioxide equivalent,  EMBED Equation.3  (tonne CO2 equiv/year)  EMBED Equation.3  (3.7) where GWP (N2O) = global warming potential of nitrous oxide = 310 Baseline methane emissions from natural gas production and leakage in transport and distribution, corresponding to heat supply, BEth fug (tonne CH4/year):  EMBED Equation.3  (3.8) where MLR = methane leakage rate in natural gas production, transport and distribution leakage, including leaks at the industrial site (kg CH4 /GJ natural gas energy consumption, lower heating value basis). ABECNG = annual baseline natural gas energy consumption for heat supply (GJ/year) In units of carbon dioxide equivalent emissions, BEth equiv fug (tonne CO2 equiv/year):  EMBED Equation.3  (3.9) where GWP (CH4) is defined as before = 21 Baseline carbon dioxide emissions for electricity supplied, BEelec (tonne CO2/year):  EMBED Equation.3  (3.10) where CEO = cogeneration electricity output (MWh/year), and BEFelec = baseline CO2 emissions factor for electricity from public supply (kg CO2/MWh) Annual electricity generation from the cogeneration system, CEO (MWh/year):  EMBED Equation.3  (3.11) where CPO = cogeneration system net power output capacity (MWe), and AOH = annual operating hours of cogeneration system (h/year) Does the country have a study quantifying its economic cogeneration potential? Cogeneration faces technological barriers Yes No Has 10% of the economic potential been reached? Yes No Is installed cogeneration capacity more than 5% of total installed thermal generating capacity? Is installed cogeneration capacity more than 500MW? Is installed number of cogeneration more than 25? Cogeneration does not face technological barriers One or more Yes All No Cogeneration faces technological barriers Cogeneration does not face institutional barrier A Yes Does cogenerator receive preferential tariffs, financing and/or fiscal benefits compared to other generators? No Does cogenerator face economic penalties when the system is down, penalties that are more onerous than those faced by other generators when they are down and unjustified on a purely economic basis? Yes Cogeneration faces institutional barrier A No Test is inconclusive with respect to institutional barrier A Have energy service companies (ESCOs) installed package cogeneration systems at energy users locations? No Yes Package cogeneration faces institutional barrier B No Have ESCOs conducted at least 20 recent installations in the country or a number of installations representing 5% of total installed thermal generating capacity in the country? Yes Package cogeneration does not face institutional barrier B Carbon dioxide emissions from natural gas combustion in the cogeneration system, ECS (tonne CO2/year):  EMBED Equation.3  (4.1) where AECNG = annual energy consumption of natural gas in cogeneration system (GJ/year), and EFNG = CO2 emission factor of natural gas (kg CO2/GJ, lower heating value basis) Methane emissions from natural gas combustion in the cogeneration system, Emet comb (tonne CH4/year), are given by:  EMBED Equation.3  (4.2) where AECNG = annual energy consumption of natural gas in the cogeneration system (GJ/year), and MEF = methane emission factor for natural gas combustion (kg CH4/TJ, lower heating value basis) In units of carbon dioxide equivalent emissions, Eequiv met comb (tonne CO2 equiv/year)  EMBED Equation.3  (4.3) where GWP (CH4) = global warming potential of methane = 21 Nitrous oxide emissions from natural gas combustion in the cogeneration system,  EMBED Equation.3  (tonne N2O/year), are given by:  EMBED Equation.3  (4.4) where AECNG = annual energy consumption of natural gas in the cogeneration system (GJ/year), and NEF = nitrous oxide emission factor for natural gas combustion (kg N2O/TJ, lower heating value basis) In units of carbon dioxide equivalent emissions,  EMBED Equation.3  (tonne CO2 equiv/year)  EMBED Equation.3  (4.5) where GWP (N2O) = global warming potential of nitrous oxide = 310 Yes No Cogeneration by industrial user faces institutional barrier B Have industrial energy users conducted at least 20 recent installations in the country or a number of installations representing 5% of total installed thermal generating capacity in the country? Have industrial energy users installed package cogeneration systems at their site locations or at any of their associated companies (mother, sister, daughter) in the same country? 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