CDM Project Colombia Gas Natural

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 02 CDM Executive Board page 1

This template shall not be altered. It shall be completed without modifying/adding headings or logo, format or font

CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 02 - in effect as of: 1 July 2004)

CONTENTS A. General description of project activity B. Application of a baseline methodology C. Duration of the project activity / Crediting period D. Application of a monitoring methodology and plan E. Estimation of GHG emissions by sources F. Environmental impacts G. Stakeholders comments

Annexes Annex 1: Contact information on participants in the project activity Annex 2: Information regarding public funding Annex 3: Baseline information

Annex 4: Monitoring plan



SECTION A. General description of project activity A.1 Title of the project activity:

Umbrella Fuel-Switching Project in Bogot and Cundinamarca

Version 03 30 April 2006

A.2. Description of the project activity:

The project activity primarily aims at reducing GHG emissions through fuel switching. The project consists of investment to replace the use of liquid petroleum fuels by natural gas, funded through the sale of carbon credits in the context of the Clean Development Mechanism (CDM) of the Kyoto Protocol.

Eight companies lead this fuel-switching project, which involves the conversion of equipment of their industrial facilities located in the Colombian Department of Cundinamarca.

For this project activity, the companies are represented by Gas Natural S.A. E.S.P. that is considered as the Colombian project participant.

Gas Natural S.A. E.S.P. is a consolidated company with over 13 years of experience as a leading distributor of natural gas. In 1998 it was acquired by the Gas Natural SDG group (a Spanish multinational company), that is part of CAIXA and REPSOL groups. The company distributes natural gas to 1.3 millions residential and industrial users in Bogot and the nearby Departments of Cundinamarca and Boyac.

The companies involved in this project activity are shown in Table 1:

Table 1: companies involved

Company Industrial Sector

Bavaria S.A. Brewery

Protela S.A. Textile industry

Alpina S.A. Food industry (mainly milk-derived products).

Suizo S.A. Food industry (meat-derived products)

Proalco S.A. Wire production facility

Sigra S.A. Vegetal and animal fat production facility

Icollantas S.A. Rim production facility

Peldar S.A. Crystal production facility

Currently, the industrial facilities consume residual fuel oil to generate steam and process heat. Table 2 shows the average annual fuel consumption of each plant and the processes in which this fuel is consumed:



Table 2: processes and fuel consumption

Process Company Steam

generation Thermal oil

heating Baking and glass and wire

production in furnaces

Average fuel consumptionGJ/year

Bavaria 763,865

Protela 166,187

Alpina 148,386

Suizo 34,173

Proalco 51,683

Sigra 300,622

Icollantas 176,077

Peldar 443,994

Total 2,084,986

The total average residual fuel oil consumption of the industries participating in this project activity is 2,084,986 GJ/year, 23.8% of which is used in furnaces, 73.8% in boilers, and 2.4% in thermal oil heating.

The project activity registration under the CDM will allow the industries to minimize the economic disadvantages related to the fuel substitution cost and the higher fuel cost, keeping in mind the lower price of residual fuel oil in comparison with the price of natural gas.

The proposed project activity has the capacity to produce GHG emission reductions by 326,675 tCO2e over a 10-year crediting period. The project also brings the inherent benefits of switching residual fuel oil to natural gas:

Improvement of air quality due to less emission of local pollutants such as NOx, SOx, and particulate matter.

Improvement of labor and health conditions of its employees. Lower potential sources of risks, because natural gas does not require any storage. Lower maintenance of the equipment. Lower dirtiness and corrosion at the plants. Continuous supply of fuel. Less vehicular traffic due to elimination of fuel delivery trucks and therefore less risk of

accidents as well as elimination of tailpipe emissions from these vehicles.



Thus, the project brings social, environmental, and economic benefits, contributing to the sustainable development objectives of the Colombian Government, in accordance with Law 99/1993 and national policies tending to a better life quality (e.g. Rational Use of Energy and Cleaner Production) that can be found in the web site of the Ministry of Environment, Housing, and Spatial Planning of Colombia www.minambiente.gov.co.

The project has obtained the national approval from the Colombian DNA, confirming that the project contributes to the sustainable development of Colombia. In addition, the project has also obtained the national approval from the Spanish DNA.

A.3. Project participants:

Table 3: project participants

Name of Party involved Private or public entity

Is the Party involved a

project participant?

Colombia (Host) Gas Natural S.A. E.S.P. (private) No

Spain Gas Natural (private) No

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

A.4.1.1. Host Party(ies):

Colombia

A.4.1.2. Region/State/Province etc.:

Cundinamarca Department

A.4.1.3. City/Town/Community etc:

Bogot, Sibate, Sopo, and Cogua



A.4.1.4. Detail of physical location, including information allowing the unique identification of this project activity (maximum one page):

The project is carried out at eight industrial facilities located in Bogot, Sibate, Sopo y Cogua, in the Colombian Department of Cundinamarca (Figures 1 and 2).

Bogot is the capital of the country and of Cundinamarca Department. Bogotas area is 1,750 km2 and it is home to 7.5 million inhabitants (according to the 2005 census).

Cundinamarcas area is 23,960 km2 and it is home to 15.5 million inhabitants including Bogots population (according to the 1993 census). Its limits are Boyac in the North; Meta, Huila, and Tolima in the South; Tolima and Caldas in the West; and Boyac and Meta in the East.

Figure 1: map of Colombia showing Cundinamarca Department



A.4.2. Category(ies) of project activity:

The project activity involves fuel switching from residual fuel oil to natural gas at industrial facilities.

The corresponding category is: (4) Manufacturing industry.

A.4.3. Technology to be employed by the project activity: The project is based on fuel switching from residual fuel oil to natural gas and involves the conversion of the existing equipment, in accordance to the infrastructure, the productive process, and the investment capacity of each industry participating in the proposed project activity.

Table 4 shows the equipment involved in the proposed project activity.

Figure 2: map of Cundinamarca Department showing its municipalities



Table 4: equipment involved

Company Equipment Quantity Characteristics Conversion

Boiler Distral A1825

1 Fire tube, three steps 125 psi Saturated steam 600 BHP

Boiler Distral A1874

1 Fire tube, three steps 125 psi Saturated steam 700 BHP

Alpina

Boiler Titusville 7104

1 Fire tube, two steps 125 psi Saturated steam 380 BHP

Installation of Maxon regulation trains, with Fisher regulators. Combustion control:

electronic modulation with Honeywell servomotors and Siemens PLC. This allows adjusting the combustion load in ten different positions, from low load to high load.

Boiler Ateliers Henry Lardet 1402, pack 31S

1 Water tube 20 tonne/hr of steam 1,275 BHP

Icollantas

Boiler Distral A- 741, AGM-134

1 Water tube 18 tonnes/hr of steam 34 Bar (500 psi)

Flame security is controlled with Honeywell equipment. Regulation trains are

controlled by Normal regulators and Maxn security systems. Mix rings were redesigned

to operate with natural gas.

Furnace 116A 1 16 burners Korting ZL5 of 142.5 kg/hr 2 heaters Hauck LHE45C of 48 kW

Peldar

Furnace 113B 1 6 burners Laidlaw Drew C4/20/12/8 of 87 gallons/hr 2 heaters Combustin Tec Inc of 300 gallons/hr and 70 kW

Tech combustion system and Dresser control system. Adaptation of gas and fuel

oil trains as backup fuel. Medium velocity burners.

Boiler Distral A-758

1 Fire tube 300 psi 600 BHP Automatic feeding

Installation of Fisher and Honeywell regulation trains Oxygen control in close

loop.

Boiler Distral A 2021

1 Fire tube 350 psi 900 BHP Automatic feeding

Baltur natural gas burner. Landis electronic

combustion control system.

Sigra

Boiler Geka Wmetech 6473

1 100 BHP 1,337 psi Automatic feeding

Baltur bi-fuel burner. Landis electronic




Boiler Power Master A 2601

1 Fire tube 150 psi 300 HP

Suizo

Boiler Power Master A 2616

1 Fire tube 150 psi 300 HP

Fisher and Honeywell regulation trains.

Lead Furnace 1 16 burners of 150,000 Btu/hr Originally, this furnace had bi-fuel burners that were adjusted to operate with natural gas.

Proalco

Zinc Furnace 1 20 burners of 150,000 Btu/hr Originally, this furnace had bi-fuel burners that were adjusted to operate with natural gas.

Bavaria Boiler Sulzer

2 Water tube 40 tonnes/hr of steam 17 Bar Over heating steam

Flame security is controlled with Honeywell equipment. Regulation trains are

controlled by Normal regulators and Maxn security systems. Mix rings were redesigned

to operate with natural gas. Installation of oxygen

sensors in stack gases.

Boiler Inflan/Weishaupt

1 2 Mkcal Dual burner in thermal fluid process

Originally, this boiler had bi-fuel burners that were adjusted to operate with natural gas.

Boiler Konus 4 Baltur BGN300

1 2 Mkcal Burner in thermal fluid process



Boiler Konus 2 Kromschroder

1 2 Mkcal Burner in thermal fluid process Variable flow

Krom Schoereder and Dungs regulation trains. This is a backup boiler.

Boiler Distral 1 Baltur GIE10DSPGN

1 500 BHP Burner in steam process



Boiler Distral 2 Baltur GI mist 420

1 400 BHP Dual burner

Baltur bi-fuel burner. Landis electronic


Protela

Boiler Distral 3 Kromschroder

1 400 BHP Variable flow

Fisher and Honeywell regulation trains. This is a backup boiler.



In order to monitor natural gas consumption at each industrial facility, the installation of the following natural gas flow meters is carried out:

Table 5: natural gas flow meters

Company Number of meters

Meter Characteristic

Type of meter Brand Corrector Unit

Bavaria 2 G-400

Fluxi TZ2000

Turbine

Turbine

Schlumberger Mercury

Peldar 1 6-GT Turbine American Meter Mercury

Alpina 1 4-GT Turbine American Meter Mercury

Proalco 1 16M-175 Rotator Dresser Mercury

Protela 3 6-GT

16M-175

G-160

Turbine

Rotator

Rotator

American Meter

Dresser

Romet

Mercury

Sigra 1 16M-175 Rotator American Meter Mercury

Icollantas 2 4-GT (one stand-by unit)

Turbine American Meter Mercury

Suizo 1 16M-175 Rotator Dresser --

In addition, the installation of the natural gas pipeline supplying the industrial sites is also included in the project activity.

Figure 3 shows the required infrastructure for the natural gas supply.

Figure 3: natural gas supply



where

1. Industrial link-ups

2. Measurement and regulation station

3. Cut valve

4. External pipeline

5. Internal pipeline

6. Regulation train for equipment

7. Adaptation of the room (tails and equipment)

In addition, Figure 4 shows details of the industrial link-ups and the regulation train.

Figure 4: industrial link-ups and regulation train



The following composition of natural gas1 is expected:

Table 6: typical composition of natural gas

% vol

Methane 78.692

Carbon Dioxide 5.062

Nitrogen 0.536

Ethane 10.123

Propane 4.022

Butane 0.628

Pentane 0.136

Hexane 0.046

Others 0.755

A.4.4. Brief explanation of how the anthropogenic emissions of anthropogenic greenhouse gas (GHGs) by sources are to be reduced by the proposed CDM project activity, including why the emission reductions would not occur in the absence of the proposed project activity, taking into account national and/or sectoral policies and circumstances:

The proposed CDM project has the capacity to reduce the GHG emissions by replacing a more carbon intensive fuel (residual fuel oil) by natural gas.

By reducing residual fuel oil use at the project site, the project also reduces carbon dioxide emissions from fuel transportation to the industrial facilities.

On the other hand, by increasing natural gas use at the project site, the project increases fugitive methane emissions in the natural gas processing and pipeline supply to the project site, and leaks at the site.

Thus, the project affects carbon dioxide, methane, and nitrous oxide emissions. Overall, the project has the capacity to reduce GHG emissions by 326,675 tCO2e over a 10-year crediting period. Project additionality is analysed using the tool proposed in the approved baseline methodology AM0008: Industrial fuel switching from coal and petroleum fuels to natural gas without extension of capacity and lifetime of the facility.

Details are provided in Section B.3 of this PDD.

1 Source: Gas Natural S.A. E.S.P.



A.4.4.1. Estimated amount of emission reductions over the chosen crediting period:

The project has the capacity to reduce GHG emissions by 326,675 tCO2e over a 10-year crediting period.

Table 7: emission reductions during the crediting period

Years Annual estimation of emission reductions

(tonnes of CO2e)

2004 30,431

2005 30,842

2006 31,310

2007 31,855

2008 32,431

2009 32,903

2010 33,402

2011 33,931

2012 34,490

2013 35,081

Total estimated reductions (tCO2e) 326,675

Total number of crediting years 10

Annual average over the crediting period of estimated reductions (tCO2e)

32,667

A.4.5. Public funding of the project activity:

No funds from public national or international sources were used in any aspect of the proposed project.



SECTION B. Application of a baseline methodology

B.1. Title and reference of the approved baseline methodology applied to the project activity:

The project activity uses an already existing baseline methodology (AM0008), which has been approved and made publicly available by the CDM Executive Board in June 2004. The baseline methodology is designated Industrial fuel switching from coal and petroleum fuels to natural gas without extension of capacity and lifetime of the facility.

B.1.1. Justification of the choice of the methodology and why it is applicable to the project activity:

The methodology AM0008 is applicable to a project activity, which is to switch the industrial fuel currently used in some element processes of a facility to natural gas from coal and/or petroleum fuels that would otherwise continue to be used during the crediting period under the following conditions:

The local regulations/programs do not constrain the facility from using coal/petroleum fuels;

Use of coal and/or petroleum fuels is less expensive than natural gas per unit of energy in the country and sector;

The facility would not have major efficiency improvements during the crediting period; The project activity does not increase the capacity of final outputs and lifetime of the

existing facility during the crediting period, and

The proposed project activity is defined as fuel switching applied to element processes and does not result in integrated process change, except for possible changes in other energy use associated to fuel switching.

As mentioned above, the proposed project activity involves fuel switching from residual fuel oil to natural gas at eight industrial facilities. The project does not result in integrated process change, but only involves fuel switching of equipment through its conversion.

The continuation of the current situation is in line with applicable regulations in Colombia. Legally binding norms established by the government that can be related to the project activity, are those dealing with air quality, under the authority of the Ministry of Environment, Housing, and Spatial Planning. Neither of these norms constrains the facility from using residual fuel oil. The continuation of the current situation is not prevented by regulations.

Residual fuel oil is cheaper than natural gas in the region. Moreover, fuel substitution from fuel oil to natural gas would require investment for the conversion of the existing equipment. The additional investment and higher fuel cost imply that the project would not be cost effective.

The companies do not expect to increase the capacity of final outputs or the lifetime of the existing facilities during the crediting period, since the lifetime of existing equipment of the plants are longer than the crediting period.



Additionally, the companies do not expect to carry out significant efficiency improvements. There will be only the minor energy savings inherent to switching residual fuel oil to natural gas.

Thus, the proposed project activity meets the conditions under which the methodology AM0008 is applicable.

B.2. Description of how the methodology is applied in the context of the project activity:

In order to calculate ex-ante baseline emissions from fuel combustion, residual fuel oil consumption during the crediting period is estimated according to the average annual fuel consumption of each industrial facility calculated from historical data, and considering the fuel consumption growth rate estimated by each company for the next years.

However, the actual baseline proposed is dynamic, taking into account actual changes in fuel consumption over time, following project implementation. Thus ex-post baseline emissions are calculated during the monitoring process. Such a dynamic baseline is both realistic and easy to determine using the same monitoring plan used to determine project emissions.

The consumption of natural gas following project implementation would replace a certain amount of residual fuel oil consumed in the absence of the project. Thus, baseline emissions from fuel combustion are not fixed to a predetermined time-dependent value but are updated annually through the monitoring process. The baseline and project fuel consumption of an element process (in energy units) are related to each other by the fuel efficiency of the element process using residual fuel oil prior to fuel switching, and using natural gas following project implementation. The heat output of the element process is considered the same in the baseline and project scenarios.

A dynamic baseline is likely to increase the environmental integrity of the project. The time-dependent nature of the dynamic baseline is more suited to the project situation, because fuel consumption depends on plant output, which depends on market and other conditions. Plant output does not depend on the fuel the plants are using in the production process (residual fuel oil under the baseline or natural gas under the CDM project activity).

GHG emissions are made up of carbon dioxide, methane, and nitrous oxide emissions from fuel combustion and fugitive methane emissions from natural gas production, processing, transport and distribution.2

Carbon dioxide emissions from fuel combustion are determined from the emission

factor given by the IPCC for each fuel. Methane and nitrous oxide produced in the combustion are estimated using IPCC

standard emission factors for each fuel and equipment type. Fugitive methane emissions from natural gas production, processing, transport, and

distribution are obtained by the natural gas consumption of each year, using a region-specific emission factor given by the IPCC.

2 Carbon dioxide emissions from residual fuel oil transport are not considered in the calculation of emission reductions as a conservative assumption.



Total methane emissions (from fuel combustion and fugitive emissions) are converted to equivalent CO2 emissions using a GWP of 21, as agreed on for the First Commitment Period of the Kyoto Protocol.3

Similarly, nitrous oxide emissions are converted to equivalent CO2 emissions using a GWP of 310, as agreed on for the First Commitment Period of the Kyoto Protocol.

According to the baseline methodology, the key data used to determine the ex-post baseline scenario is given in Table 8.

Table 8: key data

Parameters Data sources

Carbon dioxide emission factor of residual fuel oil, CEFRFO (kgCO2/GJ)

IPCC default value

Oxidation factor for residual fuel oil IPCC default value

Methane emission factor of residual fuel oil, MEFRFO (kgCH4/TJ)

IPCC default value

Nitrous oxide emission factor of residual fuel oil, NEFRFO (kgN2O/TJ)

IPCC default value

Global Warming Potential of methane, GWP (CH4) According to Article 5, Section 3 of the Kyoto Protocol, GWP is as agreed on at COP3

Global Warming Potential of nitrous oxide, GWP (N2O) According to Article 5, Section 3 of the Kyoto Protocol, GWP is as agreed on at COP3

Lower heating value of natural gas, LHVNG (kJ/m3) Gas Natural S.A. E.S.P.

Efficiency of the element process n using residual fuel oil prior to project implementation, RFO n

Industrial facilities

Variables Data sources

Quantity of natural gas consumed at the element process n following project implementation, PFCNG n (m3)


Efficiency of element process n using natural gas following project implementation, NG n


3 Article 5.3 of the Kyoto Protocol establishes: The global warming potentials used to calculate the carbon dioxide equivalence of anthropogenic emissions by sources and removals by sinks of greenhouse gases listed in Annex A shall be those accepted by the Intergovernmental Panel on Climate Change and agreed upon by the Conference of the Parties at its third session. Based on the work of, inter alia, the Intergovernmental Panel on Climate Change and advice provided by the Subsidiary Body for Scientific and Technological Advice, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall regularly review and, as appropriate, revise the global warming potential of each such greenhouse gas, taking fully into account any relevant decisions by the Conference of the Parties. Any revision to a global warming potential shall apply only to commitments under Article 3 in respect of any commitment period adopted subsequent to that revision.



The assumptions regarding heating values and emission factors are unchanged throughout the crediting period.

In addition, Table 9 shows the element processes considered in the project activity:

Table 9: element processes

Element Process Description Industrial Facility 1 2 Sulzer steam boilers Bavaria

2 1 Inflan/Weishaupt thermal oil boiler

1 Konus 4 Baltur BGN300 thermal oil boiler

1 Konus 2 Kromschroder thermal oil boiler

Protela

3 1 Distral 1 Baltur GIE10DSPGN steam boiler

1 Distral 2 Baltur GI mist 420 steam boiler

1 Distral 3 Kromschroder steam boiler

Protela

4 1 Distral A1825 steam boiler

1 Distral A1874 steam boiler

1 Titusville 7104 steam boiler

Alpina

5 1 Power Master A 2601 steam boiler

1 Power Master A 2616 steam boiler

Suizo

6 2 furnaces Proalco

7 1 Distral A-758 steam boiler

1 Distral A 2021 steam boiler

1 Geka Wmetech 6473 steam boiler

Sigra

8 1 Ateliers Henry Lardet 1402, pack 31S steam boiler

1 Distral A- 741, AGM-134 steam boiler

Icollantas

9 1 furnace 116 A

1 furnace 113 B

Peldar

B.3. Description of how the anthropogenic emissions of GHG by sources are reduced below those that would have occurred in the absence of the registered CDM project activity:

The industries, where the project activity is carried out, had been consuming liquid petroleum fuels due to their low cost in the market.

The consumption of natural gas was not considered by these industries as a viable option because it was not a cost-effective opportunity due to natural gas high price.



Following the consolidation of CDM, these industries, along with Gas Natural S.A. E.S.P., considered the possibility of taking part in a CDM project activity as a way of minimizing the costs of switching to natural gas.

Besides, other benefits were also taken into account in the decision-making process that leads to the implementation of the proposed project activity, such as the contribution to Colombias Sustainable Development goals, a better air quality, a continuous fuel supply, and lower cost of equipment maintenance, among others.

Natural gas is more expensive than residual fuel oil in Colombia. Moreover, switching liquid petroleum fuels by natural gas requires a huge initial investment in adapting equipment technology.

Initial investment and higher fuel cost determinate the project is not cost effective.

As mentioned above, project additionality is analyzed according to methodology AM0008.

Legal and regulatory requirements

The continuation of the current situation is in accordance with the national regulations. There is not any restriction to petroleum fuels consumption or commercialization that is used by the industries participating in the project activity.

Legal regulations established by the government that could be related to the proposed project activity, are those referred to air quality, such as Law 99/1993, Decree 948/1995, and Decree 02/1982. These can be found in the Ministrys web site www.minambiente.gov.co.

All industries participating in the proposed project activity are in compliance with emission limits for local pollutants.

None of these regulations is forcing the industries to implement the proposed project activity. The continuation of the current situation is not prevented by the regulations in force.

Residual fuel oil and natural gas consumption trends in the region

Although fuel price behavior is not stable in Colombia, natural gas is more expensive than liquid petroleum fuels, residual fuel oil, and non-distillate oil mainly. This is the reason why exists a notable tendency in preferring petroleum fuels instead of natural gas in the region.

In 2002, barriers that prevented big industries that consumed residual fuel oil and non-distillate oil to switch by natural gas existed. These barriers are described as follows:

Switching to natural gas did not represent an economical benefit because natural gas costs were not profitable.

Heavy fuel oil prices are not regulated, so industries can freely negotiate the price they consider more suitable with the provider.

The natural gas tariff includes the costs of supply and the costs of transporting natural gas. Both costs were subject to the variations of the international oil market, what makes it more variable.

Investment costs related to technology to be applied, internal network construction and measurement and Regulation Stations installation, made the project not cost-effective for the industries.



The industries that have switched to natural gas were those that consumed LPG and fuel oil N2. Besides, as its consumptions were low, fuel prices were regulated so they were not able to negotiate with the provider.

Investment Analysis

This assessment includes the following elements:

Establishment of price scenarios for petroleum fuels and natural gas. Determination of equipment operational lifetime, efficiency, costs, and investment. Definition of the most adequate discount rate and determination of return rates.

Price Scenarios

The scenarios under consideration where proposed by UPME (Unidad de Planeacin Minero Energtica Energy and Mining Planning Unit) for the next 10 years. This projection was based on three price scenarios of WTI crude oil prices.

The three WTI oil price scenarios are:

Low Scenario: it was based on the CONFIS (Consejo Distrital de Poltica Econmica y Fiscal Economic and Fiscal District Council) scenario.

Medium Scenario: this scenario was accorded with Ecopetrol. High Scenario: the medium scenario of the United States Department of Energy (DOE)

projection was considered.

These scenarios are shown in Figure 5 below.

19,0

20,0

21,0

22,0

23,0

24,0

25,0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

US$ CORRIENTES / BL

Escenario Confis Escenario Medio Escenario EIA

Figure 5: WTI oil price scenarios projection



Based on WTI oil price scenarios, UPME defined three price scenarios for different fuels such as residual fuel oil, diesel, liquid petroleum gas, kerosene, and natural gas. Table 10 and Figure 6 show the three price scenarios established, which are used in the economic assessment of this project.

Table 10: fuel price scenarios projection

Fuel Prices4 ($/MBtu)

Diesel Kerosene Residual Fuel Oil Liquid Petroleum Gas Bogot Natural Gas Bogot Year

Low Medium High Low Medium High Low Medium High Low Medium High Low Medium High 2004 20,944 17,192 22,717 19,659 19,659 19,659 8,405 7,827 9,129 27,563 27,563 27,563 14,570 14,655 14,6942005 22,665 22,148 24,306 19,227 14,959 18,525 9,005 8,760 9,683 23,799 22,642 25,252 15,626 15,533 15,6262006 22,950 22,494 25,779 18,948 15,371 18,075 8,973 8,757 10,228 24,749 24,282 26,040 16,427 16,768 17,3282007 24,234 24,227 27,275 18,160 14,808 18,264 9,410 9,406 10,795 25,206 24,795 27,593 17,275 18,115 19,4942008 25,593 26,085 28,862 18,243 15,209 18,441 9,871 10,104 11,397 26,609 26,602 29,238 18,208 19,473 21,5522009 27,041 28,610 30,544 18,329 15,612 18,622 10,361 11,410 12,036 28,093 28,534 30,985 19,295 20,630 22,8232010 28,577 31,338 32,329 18,427 16,339 18,806 10,881 12,188 12,714 29,667 31,072 32,833 20,462 21,870 24,1842011 30,187 30,732 34,232 18,529 17,070 18,993 11,429 11,678 13,438 31,332 33,799 34,792 21,715 23,200 25,6422012 31,892 33,092 36,241 18,623 15,884 19,191 12,008 12,558 14,201 33,115 33,585 36,902 23,063 24,630 27,2062013 33,698 35,624 38,373 18,721 16,301 19,386 12,619 13,501 15,011 35,002 36,036 39,129 24,515 26,168 28,886

4 Natural gas price does not include the 8.9% contribution to the Solidarity Fund.



Fuel price projection

(low scenario)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

$

/

M

B

t

u

DIESEL KEROSENE

RESIDUAL FUEL OIL LPG Bogot

NATURAL GAS Bogot

Fuel price projection (medium scenario)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

$

/

M

B

t

u

DIESEL KEROSENE


NATURAL GAS Bogot

t

Fuel price projection (high scenario)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

$

/

M

B

t

u

DIESEL KEROSENE


NATURAL GAS Bogot

Figure 6: fuel price scenarios projection



Investment

The cost of switching the existent equipment from petroleum fuels to natural gas was determined for each industry. These investments include costs associated to internal natural gas supply networks, burners, measure and regulation stations, and control equipment, among others.

Table 11 shows the necessary investment for the completion of the project activity.

Table 11: required investment

Company Investment

(Million Colombian pesos, COP)5

Peldar 879

Sigra 200

Protela 483

Icollantas 307

Proalco 59

Bavaria 1,006

Suizo 51

Alpina 283

Total 3,267

Equipment

The equipment involved in the project activity has a remaining operating lifetime higher than 10 years, considered as crediting period of the present project.

Economic Assessment

This assessment has been carried out using a Net Present Value analysis. NPV is estimated by taking into account the project investment and the incremental flows modified by fuel cost6, over a 10-year period and using an adequate discount rate.

The economic assessment named above, will be based on each fuel price scenario determined by UPME.

The discount rate used for the NPV is known as WAAC (Weighted Average Cost of Capital).

Table 12 shows the method and data used in the discount rate calculation:

5 Exchange rate: 1 USD = 2,303 COP 6 Operating cost differences are not taking into account since these are negligibly small in comparison with fuel cost differences.



Table 12: discount rate calculation

Capital cost (USD) Abbreviation Parameters Observations

Debt D 45.6 %

Own funds RP 54.4%

Risk free rate Ri 4.87% T-Bonds tcm 30y media 1993-2003

Market profitability Rm 12.63% Source: Damodarn

Country risk rate P 5.62% Yankees 2020 vs T-Bonds tcm 20y (media 2 years)

not leveraged u 0.73 Source: Revista Dinero: Junio 12 2003 No 183, average of Textile, Beverage, and Food Sectors.

leveraged 1.11

Capital cost before taxes (USD) Ke 19.07%

Projected devaluation (COP/USD) Dev 3.73% Parity IPC Col vs. CPI EEUU projected next years

Forecasted inflation Inf 6.49%

Debt cost (COP) Kd 12.9% DTF average 2002 + 4%

Tax rate Tc 38.5%

WACC nominal after taxes WACC (at) 16.40%

WACC nominal before taxes WACC (bt) 18.66%

WACC actual before taxes WACC (act) 11.43%

Ke = Ri + * (Rm - Ri) + P

WACC (at) = Ko = D * Ki (1 Tc) + RP * Ke / (1 - Tc)

WACC (bt) = WACC (at) / (1 - Tc)

WACC (act) = (1 + WACC (bt)) / (1 + Inflacin EEUU) - 1

The following parameters are considered in the discount rate estimation:

Debt: average capital structure, for year 2003, of the companies that are part of the project

activity.

Capital Cost: its calculation is based on the CAPM (Capital Assets Price Model) methodology, which considers a risk-free rate, a market return rate, and a country risk rate.

Debt Cost: it depends on each company, on their access to the several available market mechanisms, etc. A DTF + 4% debt cost is considered as an average cost for any of companies.

Using these parameters and following the method shown in Table 12 above, it can be determined that the discount rate to be used in the economic assessment is 18.66%, before taxes.

Net Present Value

Table 13 shows the NPV calculated for each industry.



Table 13: Net Present Value

NPV (Million COP) Company

Low scenario Medium Scenario High Scenario Peldar -8,963 -10,298 -10,248

Sigra -4,587 -4,922 -4,909

Protela -7,246 -7,750 -7,754

Icollantas -6,628 -7,160 -7,049 Bavaria -30,156 -32,382 -32,299

Proalco -2,324 -2,489 -2,499

Suizo -1,434 -1,539 -1,535

Alpina -3,319 -3,821 -3,802

Total -64,657 -70,361 -70,095

Considering the initial investment and the different fuel prices, the project NPV is negative for the three fuel price scenarios under analysis. The project activity registration will allow the industries to minimize the mentioned economic disadvantages, generating not only economic benefits but also environmental and social benefits for the community.

Therefore, the project activity registration is relevant when taking the decision whether to go ahead with the proposed project activity.

The previous analysis clearly shows that the continuation of residual fuel oil consumption represents the baseline scenario, where GHG emissions are higher than the project scenario emissions.

B.4. Description of how the definition of the project boundary related to the baseline methodology selected is applied to the project activity:

The project boundary encompasses the physical, geographical site of the industrial facilities involved in the proposed project activity.

Emission reductions should be adjusted for leakage. Leakage is defined in the CDM M&P as the net change of anthropogenic emissions by sources of greenhouse gases which occurs outside the project boundary, and which is measurable and attributable to the CDM project activity.

In accordance with this, Table 14 shows emissions and leakage in the project and baseline scenarios.



Table 14: emissions and leakage in the project and baseline scenarios

Project Scenario Baseline Scenario

Emissions Carbon dioxide (CO2) emissions associated with natural gas combustion at plant site.

Methane (CH4) and nitrous oxide (N2O) emissions from natural gas combustion at plant site.

Methane (CH4) emissions from natural gas leaks at plant site.

Carbon dioxide (CO2) emissions from residual fuel oil combustion at plant site in the baseline.

Methane (CH4) and nitrous oxide (N2O) emissions from residual fuel oil combustion at plant site in the baseline.

Leakage Methane (CH4) emissions from natural gas production, processing and pipeline leakage (natural gas pipeline outside project site).

Other leakage would be associated with gas pipeline construction to bring natural gas to the project site area. This is not included, since there are likely to be many other users as well, and in each case there will be reduced carbon dioxide (CO2) emissions from fuel switching. These emissions are excluded.

Carbon dioxide (CO2) emissions from residual fuel oil transport to the plant sites. These emissions are excluded as a conservative assumption.

B.5. Details of baseline information, including the date of completion of the baseline study and the name of person (s)/entity (ies) determining the baseline:

Date of completing the final draft of this baseline section: 30/08/2004

Name of person/entity determining the baseline: Mara Margarita Cabrera, MGM International

Carrera 43 # 7-50 Torre Financiera Dann, Medelln, Colombia Tel: (57) -4- 2662269 e-mail: [email protected]

Mara Florencia Clavin, Marisa Zaragozi, and Fabin Gaioli, MGM International SRL

Junn 1655, 1 B

C1113AAQ, Buenos Aires, Argentina

Tel./Fax: (54 11) 5219-1230/32

e-mail: [email protected]

[email protected]

[email protected]

Mara Margarita Cabrera, Mara Florencia Clavin, Marisa Zaragozi, and Fabin Gaioli are not project participants.



SECTION C. Duration of the project activity / Crediting period C.1 Duration of the project activity: C.1.1. Starting date of the project activity:

The project started in the year 2003.

Table 15 shows when the different industrial facilities started consuming natural gas.

Table 15: starting of natural gas consumption

Company Date

Bavaria Dec-03

Icollantas Dec-03

Peldar Sep-04

Proalco Dec-03

Suizo Dec-03

Sigra May-03

Alpina Nov-04

Protela Nov-03

C.1.2. Expected operational lifetime of the project activity: 30 years C.2 Choice of the crediting period and related information:

Fixed crediting period C.2.1. Renewable crediting period C.2.1.1. Starting date of the first crediting period:

N/A

C.2.1.2. Length of the first crediting period:

N/A



C.2.2. Fixed crediting period:

C.2.2.1. Starting date:

01/01/2004

C.2.2.2. Length:

10 years



SECTION D. Application of a monitoring methodology and plan D.1. Name and reference of approved monitoring methodology applied to the project activity:

The project activity uses an already existing monitoring methodology (AM0008), which has been approved and made publicly available by the CDM Executive Board in June 2004. The monitoring methodology is designated Industrial fuel switching from coal and petroleum fuels to natural gas without extension of capacity and lifetime of the facility.

D.2. Justification of the choice of the methodology and why it is applicable to the project activity:

The methodology AM0008 is applicable to a project activity, which is to switch the industrial fuel currently used in some element processes of a facility to natural gas from coal and/or petroleum fuels that would otherwise continue to be used during the crediting period under the following conditions:

The local regulations/programs do not constrain the facility from using coal/petroleum fuels; Use of coal and/or petroleum fuels is less expensive than natural gas per unit of energy in the

country and sector;

The facility would not have major efficiency improvements during the crediting period; The project activity does not increase the capacity of final outputs and lifetime of the existing

facility during the crediting period, and

The proposed project activity is defined as fuel switching applied to element processes and does not result in integrated process change, except for possible changes in other energy use associated to fuel switching.

As mentioned above, the proposed project activity involves fuel switching from residual fuel oil to natural gas at eight industrial facilities. The project does not result in integrated process change, but only involves fuel switching of equipment through its conversion.

The continuation of the current situation is in line with applicable regulations in Colombia. Legally binding norms established by the government that can be related to the project activity are those dealing with air quality, under the authority of the Ministry of Environment, Housing, and Spatial Planning. Neither of these norms constrains the facility from using residual fuel oil. The continuation of the current situation is not prevented by regulations.

Residual fuel oil is cheaper than natural gas in the region. Moreover, fuel substitution from fuel oil to natural gas would require investment for the conversion of the existing equipment. The additional investment and higher fuel cost imply that the project would not be cost effective.

The companies does not expect to increase the capacity of final outputs or the lifetime of the existing facilities during the crediting period, because the lifetime of existing equipment of the plants are longer than the crediting period.

Additionally, the companies do not expect to carry out significant efficiency improvements. There will be only the minor energy savings inherent to switching residual fuel oil to natural gas.

Thus the proposed project activity meets the conditions under which the methodology AM0008 is applicable.



D.2. 1. Option 1: Monitoring of the emissions in the project scenario and the baseline scenario The monitoring procedure and data recording will be carried out by each industrial facility. D.2.1.1. Data to be collected in order to monitor emissions from the project activity, and how this data will be archived:

ID number (Please use numbers to ease cross-referencing to D.3)

Data variable Source of data Data unit

Measured (m), calculated (c) or estimated (e)

Recording Frequency

Proportion of data to be monitored

How will the data be archived? (electronic/ paper)

Comment

1 Quantity of natural gas consumed at the element process n following project implementation

PFCNG n


m3 M Monthly 100% Paper (field record) Electronic (spreadsheet)

This value will be monitored by element process. Before calculation of project emissions, it shall be converted to energy units (GJ) by multiplying by its Lower Heating Value.

2 Total quantity of natural gas consumed at the industrial facility following project implementation

PFCNG



Before calculation of project emissions, it shall be converted to energy units (GJ) by multiplying by its Lower Heating Value. It shall be confirmed by natural gas purchase record.

3 Project emissions E


tCO2e C Monthly 100% Paper (field record) Electronic (spreadsheet)

It will be calculated using data 2, as explained in Section D.2.1.2.

Data will be archived until two years after finishing the crediting period.



D.2.1.2. Description of formulae used to estimate project emissions (for each gas,

source, formulae/algorithm, emissions units of CO2 equ.)

Project GHG emissions within the project boundary correspond to emissions from fuel combustion by equipment of the industrial facility following project implementation.

The project emissions E (tCO2e/year) are given by:

E =PFCNG [CEFNG OFNG + MEFNG GWP (CH4) + NEFNG GWP (N2O)] (1)

where:

PFCNG Total consumption of natural gas at the industrial facility in the project scenario, in energy units (GJ/year) and based on lower heating value

CEFNG Carbon dioxide emission factor per unit energy of combusted natural gas (tCO2e/GJ)

OFNG Oxidation factor for natural gas

MEFNG Methane emission factor per unit energy of combusted natural gas (tCH4/GJ)

GWP (CH4) Global warming potential of CH4 set as 21 tCO2e/tCH4 for the 1st commitment period

NEFNG Nitrous oxide emission factor per unit energy of combusted natural gas (tN2O/GJ)

GWP (N2O) Global warming potential of N2O set as 310 tCO2e/tN2O for the 1st commitment period

Ex-ante project emissions are determined through equation (1) above, using estimated values of total project natural gas consumption at the industrial facility.

Natural gas consumption is estimated ex-ante in such a way that the total heat output of each element process is the same in the baseline and project scenarios.

For each element process n, fuel consumption in the baseline and project scenarios are linked with the following constraint relation:

BFCRFOn RFOn = PFCNGn NGn (2)

where:

BFCRFO n Consumption of residual fuel oil at the element process n in the baseline scenario, in energy units (GJ/year) and based on lower heating value

PFCNG n Consumption of natural gas at the element process n in the project scenario, in energy units (GJ/year) and based on lower heating value

RFO n Efficiency of the element process n using residual fuel oil in the baseline scenario, based on lower heating value

NG n Efficiency of the element process n using natural gas in the project scenario, based on lower heating value



Baseline residual fuel oil consumption at each element process during the crediting period is estimated according to historical data and using the fuel consumption growth rate foreseen by the company.

Efficiency of each element process using residual fuel oil in the baseline is also determined from historical data of the company or taking into account conservative assumptions and it will be considered fixed along the crediting period7.

In addition, estimated efficiency of each element process using natural gas in the project is considered in the ex-ante estimation of project natural gas consumption.

The ex-ante project natural gas consumption of the element process n is estimated using equation (2), as follows:

PFCNGn = (BFCRFOn RFOn) / NGn (3)

Thus, ex-ante total project natural gas consumption is obtained as follows:

PFCNG = n PFCNGn (4)

where:

PFCNGn Consumption of natural gas at the element process n in the project scenario, in energy units (GJ/year) and based on lower heating value

Following project implementation, natural gas consumption will be monitored by element process. Total natural gas consumption at the industrial facility will be also monitored, and the measured values will be used for the ex-post calculation of project emissions using equation (1) above.

In addition, total natural gas consumption at the industrial facility shall be confirmed using equation (4) above.

7 AM0008 states that baseline efficiencies should be determined by measurements carried out prior to fuel switching as a function of the load factor. However, since this is a retroactive project, it is not possible to measure such efficiencies. Thus, conservative assumptions are considered in order to determine emission reduction.



D.2.1.3. Relevant data necessary for determining the baseline of anthropogenic emissions by sources of GHGs within the project boundary and how such data will be collected and archived:

ID number (Please use numbers to ease cross-referencing to table D.3)

Data variable Source of data Data unit

Measured (m), calculated (c), or estimated (e),

Recording frequency



Comment

1 Quantity of natural gas consumed at the element process n following project implementation

PFCNG n



This value will be monitored by element process. Before calculation of baseline emissions, it shall be converted to energy units (GJ) by multiplying by its Lower Heating Value.

4 Efficiency of the element process n using natural gas following project implementation NG n


% M Once at the early stage of the crediting period

100% Paper (field record) Electronic (spreadsheet)

The measurement of efficiency will be carried out for each element process as a function of the load factor in order to determine the average efficiency of the representative operating mode of the element process using natural gas. It is based on Lower Heating Value.



5 Quantity of residual fuel oil consumed at the element process n in the baseline

BFCRFO n


GJ C Monthly 100% Paper (field record) Electronic (spreadsheet)

It will be calculated by element process using data number 1 and 4 as explained in Section D.2.1.4.

6 Total quantity of residual fuel oil consumed at the industrial facility in the baseline

BFCRFO


GJ C Monthly 100% Paper (field record) Electronic (spreadsheet)

It will be calculated using data number 5 as explained in Section D.2.1.4.

7 Baseline emissions BE



It will be calculated using data 6 as explained in Section D.2.1.4.




D.2.1.4. Description of formulae used to estimate baseline emissions (for each

gas, source, formulae/algorithm, emissions units of CO2 equ.)

Baseline GHG emissions within the project boundary correspond to emissions from fuel combustion by equipment of the industrial facility prior to project implementation.

Baseline emissions BE (tCO2e/year) are given by:

BE = BFCRFO [CEFRFO OFRFO + MEFRFO GWP (CH4) + NEFRFO GWP (N2O)] (5)

where:

BFCRFO Total consumption of residual fuel oil at the industrial facility in the baseline scenario, in energy units (GJ/year) and based on lower heating value

CEFRFO Carbon dioxide emission factor per unit energy of residual fuel oil (tCO2/GJ)

OFRFO Oxidation factor for residual fuel oil

MEFRFO Methane emission factor per unit energy of residual fuel oil (tCH4/GJ)


NEFRFO Nitrous oxide emission factor per unit of energy of residual fuel oil (tN2O/GJ)

GWP (N2O) Global warming potential of N2O set as 310 tCO2e/tN2O for the 1st commitment period

Ex-ante baseline emissions are determined through equation (5) above, using values of total baseline residual fuel oil consumption at the industrial facility estimated according to historical data and using the fuel consumption growth rate foreseen by the company.

The ex-post baseline emissions will be calculated through equation (5) above, using values of total baseline residual fuel oil consumption determined in a dynamic manner from monitored project data.

Baseline residual fuel oil consumption will be determined ex-post in such a way that the heat output of each element process is the same in baseline and project scenarios. In other words, baseline emissions related to fuel consumption would correspond to the consumption of fuel used in the baseline scenario in order to provide the same amount of heat as is actually measured in the project scenario.

For each element process n, fuel consumption in the baseline and project scenarios are linked with the constraint relation showed in equation (2):


where:




PFCNG n Consumption of natural gas at the element process n in the project scenario, in energy units (GJ/year) and based on lower heating value

RFO n Efficiency of the element process n using residual fuel oil in the baseline scenario, based on lower heating value

NG n Efficiency of the element process n using natural gas in the project scenario, based on lower heating value

As mentioned above, the efficiency of each element process using residual fuel oil in the baseline is determined ex-ante from historical data of the company or taking into account conservative assumptions, and it will be considered fixed along the crediting period8.

In another way, following project implementation, the efficiency of each element process using natural gas will be measured as a function of the load factor. These measurements will be carried out at the early stage of the crediting period, enabling the determination of the average efficiency corresponding to the representative operating mode of the element process using natural gas. Such average efficiency will be considered as the efficiency of the element process using natural in the project scenario during the crediting period.

Following project implementation, project natural gas consumption of each element process will be monitored.

Monitored values of project natural gas consumption and determined values of efficiencies in the baseline and project scenarios will be used to calculate the ex-post baseline residual fuel oil consumption of the element process n, using equation (2), as follows:

BFCRFOn = PFCNGn NGn / RFOn (6)

Thus, total baseline residual fuel oil consumption will be obtained as follows:

BFCRFO = n BFCRFOn (7)

where:


8 AM0008 states that baseline efficiencies should be determined by measurements carried out prior to fuel switching as a function of the load factor. However, since this is a retroactive project, it is not possible to measure such efficiencies. Thus, conservative assumptions are considered in order to determine emission reduction.



D. 2.2. Option 2: Direct monitoring of emission reductions from the project activity (values should be consistent with those in section E). D.2.2.1. Data to be collected in order to monitor emissions from the project activity, and how this data will be archived: ID number (Please use numbers to ease cross-referencing to table D.3)

Data variable

Source of data

Data unit

Measured (m), calculated (c), estimated (e),

Recording frequency



Comment

N/A D.2.2.2. Description of formulae used to calculate project emissions (for each gas, source, formulae/algorithm, emissions units of CO2 equ.): N/A



D.2.3. Treatment of leakage in the monitoring plan D.2.3.1. If applicable, please describe the data and information that will be collected in order to monitor leakage effects of the project activity ID number (Please use numbers to ease cross-referencing to table D.3)

Data variable

Source of data

Data unit

Measured (m), calculated (c) or estimated (e)

Recording frequency



Comment

2 Total quantity of natural gas consumed at the industrial facility following project implementation

PFCNG



Before calculation of leakage, it shall be converted to energy units (GJ) by multiplying by its Lower Heating Value. It shall be confirmed by natural gas purchase record.

8 Leakage LE



It will be calculated using data 2 as explained in Section D.2.3.2.




D.2.3.2. Description of formulae used to estimate leakage (for each gas, source,

formulae/algorithm, emissions units of CO2 equ.)

Fugitive methane emissions from natural gas production, processing, pipeline and distribution are considered as leakage.

The leakage LE (tCO2e/year) is given by

LE = PFCNG FENG (CH4) GWP (CH4) (8)

where:

PFCNG Total consumption of natural gas in the project scenario, in energy units (GJ/year) and based on lower heating value

FENG (CH4) IPCC default methane emission factor associated with natural gas production, processing, pipeline and distribution in the project (tCH4/GJ)


Fugitive methane emissions associated with natural gas occur in natural gas production and processing as well by leakage from the pipeline supplying the project site. These emissions are emitted outside the project boundary. There would also be fugitive emissions from the natural gas distribution network within the project site. For simplicity in calculations, we consider all of these fugitive methane emissions to be outside the project boundary.

Since measured data on natural gas production, processing and pipeline leakage are not available, standard estimates are used, as suggested in IPCC Guidelines for National Greenhouse Gas Inventories Volume 3, Reference Manual (1996). Table 1-64, p. 1.131 indicates values corresponding to the Rest of the world, region where Colombia would fall: 39.59 to 96.00 tonnes of methane per PJ of natural gas for its production and 116.00 to 340.00 tonnes of methane per PJ of natural gas for its processing, pipeline and distribution.

Average values of 70.00 tCH4/PJ (0.00007 tCH4/GJ) for natural gas production and 230.00 tCH4/PJ (0.00023 tCH4/GJ) for natural gas processing, pipeline and distribution are assumed. Thus, for natural gas production, processing, pipeline and distribution, the methane emission factor considered is 0.0003 tCH4/GJ of natural gas consumption.

In this case, the energy content (GJ) is based on the lower heating value of the fuel.

Thus, to estimate the leakage before and after project implementation it is necessary to calculate the ex-ante and ex-post consumption of natural gas at the industrial facility, which can be determined as explained in Section D.2.1.2.



D.2.4. Description of formulae used to estimate emission reductions for the project activity (for each gas, source, formulae/algorithm, emissions units of CO2 equ.)

As mentioned above, baseline emissions BE, project emissions E, and leakage LE (tCO2e/year) are given by:


E = PFCNG [CEFNG OFNG + MEFNG GWP (CH4) + NEFNG GWP (N2O)] (1)

LE = PFCNG FENG (CH4) GWP (CH4) (8)

Thus the emission reductions ER (tCO2e/year) achieved by the project activity are given by:

ER = BE E LE = (9)

= BFCRFO [CEFRFO OFRFO + MEFRFO GWP (CH4) + NEFRFO GWP (N2O)]

PFCNG [CEFNG OFGN + MEFNG GWP (CH4) + NEFNG GWP (N2O)]

PFCNG FENG (CH4) GWP (CH4)

Total emission reductions should be estimated ex-ante as is shown below in Section E.5, and determined ex-post as explained in Sections D.2.1.2, D.2.1.4, and D.2.3.2 above.



D.3. Quality control (QC) and quality assurance (QA) procedures are being undertaken for data monitored

Data (Indicate table and ID number e.g. 3.-1.; 3.2.)

Uncertainty level of data (High/Medium/Low) Explain QA/QC procedures planned for these data, or why such procedures are not necessary.

1. PFCNG n Low Natural gas consumption by element process is measured by gas flow meters. These flow meters are calibrated in Natural Gas Laboratories, accredited as calibration laboratories by the Ministry of Economy of Colombia.

2. PFCNG Low Total natural gas consumption is measured by gas flow meters. The accuracy of this measure will be checked against fuel purchase records.

4. NG n Low Efficiency is obtained by analysis of combustion gases from the element processes.

The companies have a series of internal procedures that ensures data have low uncertainties during monitoring process (see Section D.4)

Emissions of NOx, SOx, and particulate matter will be measured in order to detect environmental impacts of the project and to ensure compliance with environmental regulations.



D.4 Please describe the operational and management structure that the project operator will implement in order to monitor emission reductions and any leakage effects, generated by the project activity

Each industrial facility has a representative person responsible for the documentation of monitored data. Gas Natural S.A. E.S.P as bundling agent also has a person responsible for the CDM project activity, whose mission is to collect all the information that will be entered in a database, and to carry out internal audits of the industries in order to guarantee the quality of the registries, prior to Verification by the Operational Entity.

In order to verify data quality, the industries will work in accordance with ISO 9001 Quality Assurance System, which intends to organize the information through data codification and internal audits carried out by Gas Natural S.A. E.S.P. in every industry that takes part in this project activity.

Table 16 shows the operational and management structure that will be implemented.

Table 16: operational and management structure for monitoring

Department Person Responsible Monitoring Monitoring Method

Quality, Security and Service Management

Martn Moreno Calibration and verification of rotating meters, diaphragm meters, and turbine meters.

Each meter is calibrated at Gas Natural Laboratories prior to their installation, to assure the meters exactitude.

Measurement Control Management

Adolfo Villalba Daily verification of meters installed at the industrial facilities.

The meter exactitude is systematically verified against a pattern meter in-situ. Internal Standard NT-620-COL (GNESP)

Quality, Security and Service Management

Andrs Soto Fuel Consumption monitoring in the industrial facilities. Audits in order to assure the correct implementation of the monitoring methodology.

The verification structure that includes the audits is lead under Gas Natural PGCM_170_GN and ISO 9001 procedures. The bundling agent at Gas Natural collects all the information from the industrial facilities involved in the project activity.



D.5 Name of person/entity determining the monitoring methodology:

Mara Margarita Cabrera, MGM International

Carrera 43 # 7-50 Torre Financiera Dann, Medelln, Colombia Tel: (57) -4- 2662269 e-mail: [email protected]

Mara Florencia Clavin, Marisa Zaragozi, and Fabin Gaioli, MGM International SRL

Junn 1655, 1 B

C1113AAQ, Buenos Aires, Argentina

Tel./Fax: (54 11) 5219-1230/32

e-mail: [email protected]

[email protected]

[email protected]

Mara Margarita Cabrera, Mara Florencia Clavin, Marisa Zaragozi, and Fabin Gaioli are not project participants.



SECTION E. Estimation of GHG emissions by sources E.1. Estimate of GHG emissions by sources:

As mentioned in Section D, project GHG emissions within the project boundary correspond to emissions from fuel combustion by equipment of the industrial facility following project implementation.

Thus ex-ante project emissions E (tCO2e/year) are given by:

E = PFCNG [CEFNG OFNG + MEFNG GWP (CH4) + NEFNG GWP (N2O)] (1)

= PFCNG (56.1 0,995 + 0.0014 21+ 0.0023 310)/1,000 tCO2e/GJ

As mentioned in Section D, ex-ante project emissions are determined through equation (1) above, using estimated values of total project natural gas consumption at the industrial facility.

Natural gas consumption is estimated ex-ante in such a way that the total heat output of each element process is the same in the baseline and project scenarios.

For each element process n, fuel consumption in the baseline and project scenarios are linked with the following constraint relation:


Baseline residual fuel oil consumption at each element process during the crediting period is estimated according to historical data and using the fuel consumption growth rate foreseen by the company.

Efficiency of each element process using residual fuel oil in the baseline is also determined from historical data of the company or taking into account conservative assumptions.

In addition, estimated efficiency of each element process using natural gas in the project is considered in the ex-ante estimation of project natural gas consumption.

The ex-ante project natural gas consumption of the element process n is estimated using equation (2), as follows:

PFCNGn = (BFCRFOn RFOn) / NGn (3)

Table 17 shows the efficiency values for each element process before and after project implementation that are considered for the ex-ante estimation of project emissions.



Table 17: efficiency values

Element Process Efficiency using residual fuel oil Efficiency using natural gas

1 86.35% 80.73%

2 79.85% 79.85%

3 87.02% 83.89%

4 82.87% 83.57%

5 0.2873 tonne steam/GJ 0.3122 tonne steam/GJ

6 68.00% 68.00%

7 82.84% 82.51%

8 0.2873 tonne steam/GJ 0.3122 tonne steam/GJ

9 0.1968 tonne glass/MMBTU 0.2300 tonne glass/MMBTU

Thus, ex-ante total project natural gas consumption is obtained as follows:

PFCNG = n PFCNGn (4)

The ex-ante estimations of project emissions inside the plants are shown in Table 18 below.



Table 18: ex-ante project emissions

Bavaria Protela Alpina Suizo Proalco Sigra Icollantas Peldar Total

Element process 1 2 3 4 5 6 7 8 9

2004 763,865 49,469 116,718 148,386 34,173 51,683 300,622 176,077 443,994 2,084,986

2005 763,865 49,469 116,718 161,592 34,173 52,830 315,653 176,077 443,994 2,114,371

2006 763,865 49,469 116,718 177,994 34,173 54,003 331,436 176,077 443,994 2,147,728

2007 763,865 52,437 123,721 190,453 34,173 55,202 348,007 176,077 443,994 2,187,929

2008 763,865 55,584 131,144 203,785 34,173 56,427 365,408 176,077 443,994 2,230,456

2009 763,865 55,584 131,144 218,050 34,173 57,680 383,678 176,077 443,994 2,264,244

2010 763,865 55,584 131,144 233,313 34,173 58,960 402,862 176,077 443,994 2,299,972

2011 763,865 55,584 131,144 249,645 34,173 60,269 423,005 176,077 443,994 2,337,756

2012 763,865 55,584 131,144 267,120 34,173 61,607 444,155 176,077 443,994 2,377,720

Residual fuel oil consumption in the baseline (GJ)

2013 763,865 55,584 131,144 285,819 34,173 62,975 466,363 176,077 443,994 2,419,993

Total 7,638,648 534,348 1,260,742 2,136,157 341,729 571,635 3,781,190 1,760,768 4,439,938 22,465,155

2004 817,041 49,469 121,064 147,143 31,447 51,683 301,824 162,033 379,904 2,061,609

2005 817,041 49,469 121,064 160,239 31,447 52,830 316,915 162,033 379,904 2,090,943

2006 817,041 49,469 121,064 176,503 31,447 54,003 332,761 162,033 379,904 2,124,226

2007 817,041 52,437 128,328 188,858 31,447 55,202 349,399 162,033 379,904 2,164,650

2008 817,041 55,584 136,027 202,078 31,447 56,427 366,869 162,033 379,904 2,207,412

2009 817,041 55,584 136,027 216,223 31,447 57,680 385,213 162,033 379,904 2,241,153

2010 817,041 55,584 136,027 231,359 31,447 58,960 404,473 162,033 379,904 2,276,830

2011 817,041 55,584 136,027 247,554 31,447 60,269 424,697 162,033 379,904 2,314,558

2012 817,041 55,584 136,027 264,883 31,447 61,607 445,932 162,033 379,904 2,354,459

Natural gas consumption in the project (GJ)

2013 817,041 55,584 136,027 283,425 31,447 62,975 468,228 162,033 379,904 2,396,665

Total 8,170,411 534,348 1,307,683 2,118,264 314,474 571,635 3,796,313 1,620,335 3,799,043 22,232,505

2004 46,213 2,798 6,848 8,323 1,779 2,923 17,072 9,165 21,488 116,609

2005 46,213 2,798 6,848 9,063 1,779 2,988 17,925 9,165 21,488 118,268

2006 46,213 2,798 6,848 9,983 1,779 3,054 18,822 9,165 21,488 120,150

2007 46,213 2,966 7,258 10,682 1,779 3,122 19,763 9,165 21,488 122,437

2008 46,213 3,144 7,694 11,430 1,779 3,192 20,751 9,165 21,488 124,855

2009 46,213 3,144 7,694 12,230 1,779 3,262 21,788 9,165 21,488 126,764

2010 46,213 3,144 7,694 13,086 1,779 3,335 22,878 9,165 21,488 128,782

2011 46,213 3,144 7,694 14,002 1,779 3,409 24,022 9,165 21,488 130,916

2012 46,213 3,144 7,694 14,982 1,779 3,485 25,223 9,165 21,488 133,173

Project emissions (tCO2e)

2013 46,213 3,144 7,694 16,031 1,779 3,562 26,484 9,165 21,488 135,560

Total 462,134 30,224 73,965 119,813 17,787 32,333 214,727 91,649 214,881 1,257,513

Thus, the total amount of project GHG emission is expected to be around 1,257,513 tonnes of CO2-equivalent over a 10-year crediting period.



E.2. Estimated leakage:

As mentioned in Section D, fugitive methane emissions from natural gas production, processing, pipeline and distribution are considered as leakage.

Thus, the ex-ante leakage LE (tCO2e/year) is given by:

LE = PFCNG FENG (CH4) GWP (CH4) (8) = PFCNG 0.0003 tCH4/GJ 21 tCO2e/tCH4

The ex-ante estimations of leakage are shown in the Table 19:

Table 19: ex-ante leakage



2004 817,041 49,469 121,064 147,143 31,447 51,683 301,824 162,033 379,904 2,061,609

2005 817,041 49,469 121,064 160,239 31,447 52,830 316,915 162,033 379,904 2,090,943

2006 817,041 49,469 121,064 176,503 31,447 54,003 332,761 162,033 379,904 2,124,226

2007 817,041 52,437 128,328 188,858 31,447 55,202 349,399 162,033 379,904 2,164,650

2008 817,041 55,584 136,027 202,078 31,447 56,427 366,869 162,033 379,904 2,207,412

2009 817,041 55,584 136,027 216,223 31,447 57,680 385,213 162,033 379,904 2,241,153

2010 817,041 55,584 136,027 231,359 31,447 58,960 404,473 162,033 379,904 2,276,830

2011 817,041 55,584 136,027 247,554 31,447 60,269 424,697 162,033 379,904 2,314,558

2012 817,041 55,584 136,027 264,883 31,447 61,607 445,932 162,033 379,904 2,354,459

Natural gas consumption in the project (GJ)

2013 817,041 55,584 136,027 283,425 31,447 62,975 468,228 162,033 379,904 2,396,665

Total 8,170,411 534,348 1,307,683 2,118,264 314,474 571,635 3,796,313 1,620,335 3,799,043 22,232,505

2004 5,147 312 763 927 198 326 1,901 1,021 2,393 12,988

2005 5,147 312 763 1,010 198 333 1,997 1,021 2,393 13,173

2006 5,147 312 763 1,112 198 340 2,096 1,021 2,393 13,383

2007 5,147 330 808 1,190 198 348 2,201 1,021 2,393 13,637

2008 5,147 350 857 1,273 198 355 2,311 1,021 2,393 13,907

2009 5,147 350 857 1,362 198 363 2,427 1,021 2,393 14,119

2010 5,147 350 857 1,458 198 371 2,548 1,021 2,393 14,344

2011 5,147 350 857 1,560 198 380 2,676 1,021 2,393 14,582

2012 5,147 350 857 1,669 198 388 2,809 1,021 2,393 14,833

Leakage (tCO2e)

2013 5,147 350 857 1,786 198 397 2,950 1,021 2,393 15,099

Total 51,474 3,366 8,238 13,345 1,981 3,601 23,917 10,208 23,934 140,065

Thus, the total amount of leakage is expected to be around 140,065 tonnes of CO2-equivalent over a 10-year crediting period.



E.3. The sum of E.1 and E.2 representing the project activity emissions:

The ex-ante estimations of total project emissions are the following:

Table 20: ex-ante total project emissions



2004 51,361 3,110 7,610 9,250 1,977 3,249 18,973 10,186 23,882 129,597

2005 51,361 3,110 7,610 10,073 1,977 3,321 19,922 10,186 23,882 131,441

2006 51,361 3,110 7,610 11,095 1,977 3,395 20,918 10,186 23,882 133,533

2007 51,361 3,296 8,067 11,872 1,977 3,470 21,964 10,186 23,882 136,074

2008 51,361 3,494 8,551 12,703 1,977 3,547 23,062 10,186 23,882 138,762

2009 51,361 3,494 8,551 13,592 1,977 3,626 24,215 10,186 23,882 140,883

2010 51,361 3,494 8,551 14,544 1,977 3,706 25,426 10,186 23,882 143,126

2011 51,361 3,494 8,551 15,562 1,977 3,789 26,697 10,186 23,882 145,497

2012 51,361 3,494 8,551 16,651 1,977 3,873 28,032 10,186 23,882 148,006

Total project emissions (tCO2e)

2013 51,361 3,494 8,551 17,817 1,977 3,959 29,434 10,186 23,882 150,659

Total 513,608 33,590 82,203 133,158 19,768 35,934 238,643 101,857 238,815 1,397,578

E.4. Estimated anthropogenic emissions by sources of greenhouse gases of the baseline:

As mentioned in Section D, baseline GHG emissions within the project boundary correspond to emissions from fuel combustion by equipment of the industrial facility prior to project implementation.

Thus, ex-ante baseline emissions BE (tCO2e/year) are given by:


= BFCRFO (77.37 0,99 + 0.003 21 + 0.0003 310)/1,000 tCO2e/GJ

Ex-ante baseline emissions are determined through equation (6) above, using values of total baseline residual fuel oil consumption at the industrial facility estimated according to historical data and using the fuel consumption growth rate foreseen by the company.

The ex-ante estimations of baseline emissions are the following:



Table 21: ex-ante baseline emissions



2004 763,865 49,469 116,718 148,386 34,173 51,683 300,622 176,077 443,994 2,084,986

2005 763,865 49,469 116,718 161,592 34,173 52,830 315,653 176,077 443,994 2,114,371

2006 763,865 49,469 116,718 177,994 34,173 54,003 331,436 176,077 443,994 2,147,728

2007 763,865 52,437 123,721 190,453 34,173 55,202 348,007 176,077 443,994 2,187,929

2008 763,865 55,584 131,144 203,785 34,173 56,427 365,408 176,077 443,994 2,230,456

2009 763,865 55,584 131,144 218,050 34,173 57,680 383,678 176,077 443,994 2,264,244

2010 763,865 55,584 131,144 233,313 34,173 58,960 402,862 176,077 443,994 2,299,972

2011 763,865 55,584 131,

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