CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN … filePROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03.1. CDM – Executive Board page 2 File Name: ID-MEN-TNG-PDD Version 2.1 SECTION

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03.1.

CDM – Executive Board page 1

File Name: ID-MEN-TNG-PDD Version 2.1

CLEAN DEVELOPMENT MECHANISM

PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 03 - in effect as of: 28 July 2006

CONTENTS

A. General description of project activity

B. Application of a baseline and monitoring methodology

C. Duration of the project activity / crediting period

D. Environmental impacts

E. 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:

Title: “MEN-Tangerang 13.6MW Natural Gas Co-generation Project”

Version: Version 2.1

Date of Completion: 27 April 2007

A.2. Description of the project activity:

PT Manunggal Energi Nusantara (“MEN”) is developing a cogeneration project using natural gas as fuel.

The electricity the Project generates will be supplied to three textile manufacturing companies: PT Argo

Pantes; PT Argo Beni; and PT Argo Fajar; while steam will be supplied to PT Argo Pantes. The Project is

located within the PT Argo Pantes (hereafter referred as “Argo Pantes”) bonded zone in an industrial area

of Tangerang, in Greater Jakarta, Indonesia.

Project Activity

The purpose of the Project is generation of 13.6MW of electricity and 9.5tonnes per hour of high quality

steam at 8-10 bar pressure for industrial users who are currently using grid electricity and generating

steam from fuel with higher carbon intensity than natural gas. The Project scope is the installation of five

natural gas power generators; each is equipped with a waste heat recovery boiler.

The delivered electricity will replace part of the electricity needs of Argo Pantes, Argo Beni and Argo

Fajar (or “industrial users”), which are currently purchased from the grid. The steam will be sold only to

Argo Pantes and will replace the equivalent amount of thermal generation activity at Argo Pantes‟ site.

By replacing both grid electricity and fuel with higher carbon intensity than natural gas, the Project can

reduce green-house-gas emissions by 56,909 tCO2 a year.

Thermal Situation at Argo Pantes

At present, Argo Pantes requires 35.5T/hr or less steam to run its textile machineries. Due to current

business climate, Argo Pantes does not run its machineries at full capacity and this demand therefore does

not represent the potential maximum steam demand at Argo Pantes facility.

Table 1 shows Argo Pantes‟ steam demands and its current steam generating facilities and dispatch order.

Following increasing price of oil-based fuel in 2002, Argo Pantes switched from using residual oil boiler

to coal boilers as its primary heat generating source. With this switched, Argo Pantes residual oil boilers

becomes redundant and operated only when steam demand surpassed the capacity serviceable by the coal

boilers.

Table 1 - Boiler Despatch Order at Argo Pantes before the Project

Dispatch Rank No. of boilers Boiler Fuel Type Operation Status

Total Steam

Generating

Capacity (T/hr)

Current Demand

35.5T/hr

Potential Full

Demand

43T/hr

1 2 units Coal 27T/hr

27T/hr

27 (T/hr)

2 8 units Residual oil 8.5T/hr 16T/hr

50.4 (T/hr)




Total

77.4

Total

35.5T/hr

43T/hr

The Project’s Impact

The Project implementation changes the dispatch order of all heat generating equipments at Argo Pantes.

After the Project, steam provided by MEN will be the primary steam generating source as long as it

maintains to be more economical to purchase compared to the cost to operate the coal boilers.

The new dispatch order is presented in the following table.

Table 2 – Boiler Despatch Order after the Project

Dispatch Rank No. of boilers Boiler Fuel Type Operation Status

Total Steam

Generating

Capacity (T/hr)

Current Demand

35.5 T/hr

Potential Full Demand

43T/hr

1 MEN‟s

cogeneration

system

Natural Gas

purchased from

MEN‟s Project

9.5T/hr 9.5T/hr

9.5T/hr

2 2 units Coal 26T/hr

(1 T/hr spare

capacity)

27T/hr

27 T/hr

3 8 units Residual oil Not Running 6.5T/hr

50.4 T/hr

Total

77.4

Total

35.5T/hr

43T/hr

By comparing Table 1 and Table 2, it is demonstrated that at demand of 35.5T/hr, steam from residual oil

boilers and 1 T/hr of steam from coal are eliminated. At potential full demand, the coal boiler will run at

full operation and the residual oil boiler generation is reduced from 16T/hr to 6.5T/hr or reduction of

9.5T/hr.

Despite the possibility that the Project will partially displace coal boiler heat generation, for sake of

simplification and conservativeness, it will be assumed that the Project displaces only the residual oil

boiler operations.

Residual oil is therefore deemed appropriate as the „baseline fuel‟ for the Project.

Contribution to Sustainable Development

Utilization of Cleaner Fuel

The Project supports sustainable development by adopting a cleaner fuel for power and thermal

energy provision. The Project displaces the operation of residual oil boilers operation and potentially

reduces the load of the coal boilers at Argo Pantes. In addition to reducing GHG emissions and its

associated impact to climate, this reduction also assists in combating air pollution in the greater

Jakarta area - in line with Jakarta‟s administration recent campaign for cleaner air.

Without the Project, the current textile facilities will continue to:

generate steam using fuel with higher carbon intensity than natural gas; and

utilize electricity from the grid that is generated by power plants powered by fossil fuel with

higher carbon intensity than natural gas.




Energy Efficiency Practise

The cogeneration technology employed by the Project enables heat and electricity to be produced on

a single site. This operation reduces the total amount of energy used by recovering heat in the gas

engine‟s exhaust. The Project reduces as much as 24.8% (see Annex 5.1) of the energy previously

used to generate the same amount of power and heat even before accounting for transmission loss

which stands at 11.5% of generated electricity (at source) according to a PLN Report in 20051, and

consequently contributes to sustainable development by reducing residual fuel demand.

A.3. Project participants:

Table 3 - Project Participants

Name of party involved Private and/or public entities as project

participants

Indication if party involved is

considered as project

participant

Indonesia (host) PT Manunggal Energi Nusantara No

Japan Mitsubishi UFJ Securities Co. Ltd. No

The Project is wholly owned and operated by PT Manunggal Energi Nusantara which will enter into a

direct electricity purchase agreement with PT Argo Pantes, PT Argo Beni and PT Argo Fajar and thermal

sales agreement with PT Argo Pantes. The electricity delivery will be via a private electricity mini grid

and Argo Pantes‟ steam pipeline. The Project will not export any electricity to the PLN grid.

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

A.4.1.1. Host Party(ies):

Indonesia

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

Province of Banten

A.4.1.3. City/Town/Community etc:

The Project‟s geographical location relative to Jakarta, the capital city of Indonesia is

shown in Figure 1 in Section A.4.1.4.

The Project is located inside the Argo Pantes‟ textile manufacturing facility, Jl. MH

Thamrin KM4, Cikokol, City of Tangerang. The project location relative to its users are

shown in Figure 2 in Section A.4.1.4.

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

The Project falls under the following sectoral scopes:

Sectoral Scope 1 - Energy industries (renewable - / non-renewable sources)

Sectoral Scope 4 - Manufacturing industries

A.4.3. Technology to be employed by the project activity:

1 Based on PLN 2005 Annual Report




The Project involves the installation of five gas engines, each with maximum electrical output of

2,722kW and equipped with a Therm-plant Engine Steam Economizer (TESE) with overall heat

transfer capacity of 1,371kW. The TESE technology recovers heat from the hot gas engine

exhaust to generate 9.5tonnes per hour of superheated steam at 8-10bar pressure. All equipments

are supplied by GE Jenbacher and manufactured in Austria.

It is estimated that each engine will consume about 614m3/hr of natural gas with calorific value

of 45.54TJ/ktonnes and specific gravity of 0.6538 pipelined from an offshore field operated by

BP West Java and Pertamina via PT PGN‟s gas transmission infrastructure.

A.4.4 Estimated amount of emission reductions over the chosen crediting period:

Year Period Annual Estimation of emission

reductions in tonnes of CO2e

1 September 2007 – September 2008 58,961







Total estimated emission reduction in the first crediting period

(t-CO2/yr)

412,727

Total number of crediting year 7 years

Annual average of estimated reductions over the crediting

period (t-CO2/yr)

58,961

A.4.5. Public funding of the project activity:

The Project does not involve any public funding.




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

page):

Project

Location




Figure 2 - Project site relative to its users

ARGO

FAJAR

ARGO

BENI

ARGO

PANTES

PROJECT

SITE




SECTION B. Application of a baseline and monitoring methodology

B.1. Title and reference of the approved baseline and monitoring methodology applied to the

project activity:

Methodology: AM0014 Version 03

Title: “Natural gas-based package cogeneration”

B.2 Justification of the choice of the methodology and why it is applicable to the project

activity:

Methodology AM0014 is applicable for this project activity for the following reasons:

The Project involves installation of a cogeneration system using natural gas operated by an

independent party. The consuming facilities or the end users do not own or operate the project

facility.

The Project will supply all of its electrical or thermal outputs to industrial users. This situation is

likely to remain so within the crediting period as the Project is situated within the location of one

of its industrial users and does not own or run any other activities other than heat and power

generation. It is also unlikely that the industrial user who owns the site allows the project

proponent to conduct other energy-consuming business activity within its site other than what has

been agreed.

The Project will not export any excess electricity to the public grid and do not export any excess

heat to another user. This condition is unlikely to change throughout the crediting period as the

developer business license covers for general electricity trading only which does not allow

electricity sales to the public grid. The physical location of the Project within its industrial users

eliminates the possibility of trading heat to other users.

The project activity satisfies all of the applicability conditions of the chosen methodology, and therefore

application of AM0014 is deemed appropriate.

B.3. Description of the sources and gases included in the project boundary

The following gases and emission sources are included in the project boundary. As indicated in Section

A, the baseline fuel to the Project is residual oil.

Sources Gases Comments

BASELINE Combustion of baseline fuel for the

generation of steam at Argo Pantes

CO2 Included. Major source of emission

CH4 Included. A minor source of emission

N2O Included. A minor source of emission

Production, distribution &

transportation of baseline fuel

CO2 Excluded. This is conservative

CH4 Excluded. This is conservative

N2O Excluded. This is conservative

Grid-electricity generations CO2 Included. A major source of emission

CH4 Excluded.

N2O Excluded.

PROJECT Natural gas combustion during

project activity

CO2 Included. A major source of emission

CH4 Included. A minor source of emission

N2O Included. A minor source of emission




Sources Gases Comments

Natural gas released during

production, transmission, storage and

distribution.

CO2 Excluded.

CH4 Included. A major source of emission

N2O Excluded.

B.4. Description of how the baseline scenario is identified and description of the identified

baseline scenario:

Baseline Scenario Identification Process

The most likely baseline scenario is identified by assessing the seven scenarios provided in the

methodology. As demonstrated under Section A2, the Project displaces residual oil boiler operation and

potentially coal boiler for heat generation at low peak demand.

Table 4 - Baseline Scenario Assessment

No. Scenarios Scenario applied to Project situations Credible

1 Industrial plants continue

to operate with equipment

replacement as needed,

with no change in

equipment efficiency

Power: All users continue to import electricity from PLN grid.

Heat: Argo Pantes continues to run its residual oil boilers.

Assessment:

This scenario is the continuation of current practise and therefore a

very credible situation for the following reasons:

1. Table 1 (p.2) shows that at full operation, Argo Pantes consumes

only 16T/hr of steam from its residual boilers.

This represents only 30% of all residual oil boilers capacity of

50.4T/hr. These boilers, although ageing, are in perfectly good

condition. Hence, when the service life of the current boiler ends,

Argo Pantes can simply use the next available residual oil boiler –

and therefore does not need to add residue boiler capacity during

the crediting period.

2. This scenario represents a no-investment option for all users –

which is the most preferred option considering the current

business climate for the textile industry in Indonesia which does

not encourage further capital spending.

Yes

2 Industrial plants continue

to operate with improved

efficiency new equipment

at the time of equipment

replacement

using a less carbon

intensive fuel

Power: All users continue to import electricity from PLN grid

Heat: Argo Pantes continues to operate its boilers and replace it with

new boilers at the end of the service life of the existing boilers. The

new boiler will use fuel with lower emission factor than the residual

oil.

Assessment: This scenario is not credible due to several factors:

1. The excess capacity in the residual oil boilers available to Argo

Pantes as explained in Scenario 1.

2. Apart from natural gas, the only other less carbon-intensive fuel

alternatives is diesel fuel and it‟s price per unit energy is

significantly higher than residual oil (see Table 5, p.11).

It is possible that if the price of residual oil becomes

unsustainable, Argo Pantes will invest in a more cost-effective

technology to replace the operation of these boilers. However, it is

No





likely the newly installed technology will use coal as fuel due to

its cost effectiveness as has been the demonstrated case,

historically.

In 2001, when Argo Pantes was confronted with the same

situation of hiking oil prices, the company slashed energy

expenditure through the installation of three coal boilers.

However, due to sluggish business climate in the textile industry,

only two out of the three planned coal boilers were implemented.

Since then, the additional capacity has left residual oil boilers as

redundant assets of the company.

It is therefore highly unlikely that Argo Pantes will invest in

boilers using cleaner fuel considering the significantly low price

of coal-based energy.

3 Industrial plant upgrades

thermal generating

equipment and therefore

increases the efficiency of

boiler immediately

Power: All users continue to import electricity from PLN Grid

Heat: Argo Pantes immediately upgrades its thermal generating

facility by installing a new boiler which immediately increases its

efficiency and heat output.

Assessment:

The scenario involving the retrofitting of the existing boilers is

unlikely. The current coal boilers were installed in 2002 and are still in

very good condition and run with high efficiency therefore the benefit

of retrofitting is only marginal. Similarly, the residual oil boilers are

available in excess capacity at Argo Pantes such that retrofitting these

units to gain a few extra capacities is not economical.

As elaborated in Scenario 2, it is more likely that Argo Pantes

upgrades its thermal facility by installing a new coal boiler when it

needs to do so due to increased activity. The third coal boiler was not

installed due to the unfavourable business climate, but is likely to be

implemented if Argo Pantes‟ activity returns to its full capacity.

If the Project can continue to provide economical thermal energy for

Argo Pantes through exhaust gas heat recovery, then it is likely that

the project activity prevents the industrial user to invest in coal

technology – even when Argo Pantes activity resumes to near its full

capacity.

No

4 The heat and electricity

demand of the industrial

plant is reduced through

improvements in end-use

efficiency

Power/Heat: Industrial users initiate energy efficiency programme

through power demand management that reduces its electricity and

heat consumption.

Assessment:

This scenario is highly unlikely as reduction of energy demand can

only happen through replacement of the current textile machineries

with newer ones employing technology with a higher efficiency.

However, the textile industry in Indonesia has been hit with an

increase in labour costs coupled with a sudden increase in energy costs

in 2005-2006 which is then followed with declining purchasing parity,

as well as global competition from China. Argo Pantes itself is

currently not running at full capacity due to a combination of these

factors.

As explained above, the industrial users are currently not in the best

No





financial position to invest in major textile machinery replacement in

the next few years.

5 Installation of a

cogeneration system

owned by the industrial

plant

Power/Heat: Argo Pantes, being the company with the larger demand

for thermal energy, invests in a self-owned cogeneration facility. Argo

Beni and Argo Fajar purchase electricity from Argo Pantes or PLN

Assessment:

Without a new investment from an independent company like MEN,

the industrial users will not invest in a new non-core business

technology with a less-economic cleaner fuel and technology.

As elaborated in Scenario 4, this is because the industrial users and

Indonesian textile industry in general suffers an economic downturn.

Consequently, investment in textile machineries to compete in global

market is higher on the textile manufacturer agenda than investment in

a non-core energy business.

No

6 Installation of a package

cogeneration system

owned by a company other

than the industrial plant

Power/Heat: An independent company invests in a new natural gas

cogeneration facility to provide heat and electricity for the industrial

users.

This scenario is the Project scenario without CDM and deemed

plausible until the additionality analysis in Section B.5. is conducted.

To be decided

in

Section

B.5

7 Installation of

cogeneration system by a

third party

This is the same as Scenario 6 above.

Table 5 – Fuel price comparison per unit energy

Fuel Type Local Price

in USD2

Unit for

Price

Density NCV Price per TJ Emission

Factor

Kg/L MJ/t kgCO2/TJ

Coal $ 40.003 /tonnes 25523 $ 1,567 96,100

Natural Gas $ 5.124 MMBTU $ 4,853 64,200

Residual Oil $ 0.305 L 0.88 40400 $ 8,435 77,400

Diesel Oil $ 0.475 L 0.89 43000 $ 12,406 74,100

From the above assessment it is clear that the following scenarios are plausible and credible as possible

candidates for the baseline scenario:

Scenario 1 - the continuation of current practise where all users continue to import electricity

from PLN Grid and Argo Pantes continues to operate its current boilers without replacement within

the crediting period; and

Scenario 6 – installation of a natural gas based cogeneration package by a company other than

the industrial users or the Project without CDM.

It will be demonstrated under the additionality assessment in Section B.5 that Scenario 6 faces barriers to

be implemented without CDM leaving only Scenario 1 as the baseline scenario.

2 Converted from Rupiah to USD with rate of Rp9,000 per USD

3 Based on the most widely available mid-rank coal with calorific value of 6,100kcal/kg

4 Based on values from PGN or state gas company

5 Based on values published by PERTAMINA (fuel supplier)




B.5. 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 (assessment

and demonstration of additionality):

The project proponent chooses to use “Tool for demonstration and assessment of additionality” version

03 to demonstrate the Project‟s additionality.

Step 1 - Identification of alternatives to the project activity consistent with current laws and

regulations

Sub-step 1a. Define alternatives to the project activity:

In Section B.4, it was identified that the following are possible alternatives to the proposed CDM

project activity:

a. Scenario 1 – continuation of current practise where all users continue to import electricity

from the PLN Grid and Argo Pantes continues to operate its current boilers.

b. Scenario 6 – the proposed Project without CDM

Sub-step-1b. Consistencies with mandatory laws and regulations:

In Indonesia, the control of pollutant gases such as NOx, SOx, particulate matter, CO and THC are

both mandatory and monitored by the environmental regulatory body. Emissions from the existing

boilers at Argo Pantes are continuously checked and meet the national ambient air quality standards

applied by the environmental regulatory body for these gases. The Project activity is therefore not the

only option that is in compliance with all applicable regulations.

As required under the applicable methodology, the project proponent must demonstrate additionality

through an investment analysis.

Step 2. Investment Analysis

Sub step 2a – Determine appropriate analysis method

The project proponent receives economic benefit other than CDM related income as the sold

electricity and steam generates revenue for the Project. Consequently, Option I (Simple Analyis) is

not appropriate and the available options are either Option II (Comparison Analysis) or Option III

(Benchmark Analysis). The project proponent chose to apply Option III to demonstrate the Project‟s

additionality.

Sub step 2b – Identification of appropriate benchmark

The project developer chose to use IRR as the financial indicator of choice. The chosen benchmark is

the Indonesian central bank (Bank Indonesia) inter-bank interest rate (SBI) plus additional 4%

premium normally charged by the lending bank. The central bank interest rate stands at 9.5% in

November 2006. Therefore the minimum benchmark IRR is 13.5% for 10years.

Considering other risks that the Project is exposed to including (1) currency mismatched between

costs and revenue, (2) Rupiah historical volatility, and (3) historically high inflation, an additional 3%

premium is applied to the benchmark totalling to 16.5% of internal rate return for 10 years.

This benchmark very conservative, as it is only marginally higher than the average lending rate up to

the fourth quarter of 2006 which is 16% as reported by business newspaper Jakarta Post in January

2007.

Sub step 2c – Calculation and comparison of financial indicators

Project capital cost & financing

The Project‟s total capital outlay is USD12,500,000 of which 35% is MEN‟s equity. The remainder is

financed through a USD loan with a ceiling rate of 11% per annum over 10 years.




Project Revenue

Revenue is derived from the sales of electricity and steam to the industrial users. To attract industrial

users to enter into a purchase agreement, MEN offered a lower rate pegged to market values for both

energy types – which guarantees lower-than-market energy price for the industrial users at any given

time;

Revenue from electricity sales

The Project is expected to generate a net electrical output of 95,052,000kWh of electricity

annually. This electricity will be absorbed by industrial users at a rate 3% below PLN usage

rate payable by Argo Pantes within a period or Rp582/kWh6 or USD0.065

7 at the time of

Project‟s economic evaluation.

The Project‟s annual revenue from electricity sales is expected to be IDR 53,660,790,000 or

USD 5,962,310.

Revenue from steam

The Project will generate 9.5 tonnes of steam per hour or 76,000 tonnes per year. The steam

selling rate is Rp57 per kg of steam or USD6.36 per tonne. The Project‟s annual revenue

from steam sales is expected to be IDR 4,350,240,000 or USD481,333.

MEN‟s electricity revenue is tied into PLN‟s rate – which is revisable only through

government regulation. Historically, increase in electricity rate has been sluggish and meets

large opposition. Consequently, the financial analysis was projected with annual growth rate

of 2.5%.

Project costs

The major costs are derived from the cost to purchase natural gas, and annual operation costs such as

man-power and maintenance.

Costs to purchase natural gas

In mid-2006 when the project was under evaluation, the natural gas price applicable to MEN

was USD5.12/MMBTU8 or USD4,858/TJ. The Project will consume circa 730.6TJ/yr of

natural gas or annual spending of USD3,549,066 per year.

At the end of 2006, the state gas pipeline company PT PGN announced that this rate will be

increased to USD5.50 or 7.4% increase by 2007 before the project commissioning. Based on

this price hike, international gas price of USD7, and outlook of natural gas demand

domestically and globally, the IRR calculation applies a conservative 7% annual increase of

natural gas price.

Overhead costs

Overhead cost for the Project consists of the cost to maintain the unit (spare parts, etc.) and

staff salaries and expected to be no more than 5% of the capital outlay or USD 625,000.

Considering local inflation of 17% in 2005 and 6.16% in 2006, it is expected that this costs

will rise by at least 5% annually in subsequent years.

Calculated IRR

6 PLN rate is based on a basic price compounded with progressive rate based on load, therefore will vary with usage.

This rate is calculated based on the industrial user electrical consumption.

7 Currency exchange rate stands at Rp9,000 per 1 USD is assumed for Project‟s economic evaluation in 2006

8 PGN rate is based on a material price compounded with transmission rate (or toll charges), therefore will vary with

usage. This rate is calculated based on the Project projected natural gas consumption.




As stipulated by the Tool for demonstration and assessment of additionality, for benchmark

investment analysis, IRR is to be calculated as a Project IRR, not equity IRR and therefore not taking

into account the costs to finance the Project.

Based on the above-mentioned revenues, costs, and projected growth, the calculated cash flow Project

IRR for 10 years is 5% - well below the previously set benchmark, and as stipulated in Tool for

demonstration and assessment of additionality is not a financially attractive investment.

Sub step 2d – Sensitivity analysis

Increased sales price of electricity

The Project revenue from electricity sales is 3% below PLN‟s rate. PLN rate is therefore the

maximum selling price for industrial users to use MEN‟s services. If the rate of electricity is

increased to equal with PLN rate, the IRR increased to 8%. If the PLN rate is increased by

5%, the IRR moves to 10%.

Increased sales price of steam

At the time of project economic assessment, Argo Pantes was able to produce steam using

coal at a rate of IDR60 per kg. The revenue contribution from steam sales is less significant

such that if the Project can increase the steam revenue to up to IDR65 per kg or 14% from the

original rate, the IRR is up by only 1% to 6%.

Increased sales and electricity revenue

If the rate of sales and electricity revenue described above are increased at the same time, the

IRR increases to 13%.

Lower capital expenditure

If the capital cost is lowered by 10%, the IRR improves to 10%.

Conclusion from sensitivity analysis

The sensitivity analysis above demonstrates that increases in revenues in addition to the

expected growth rate applied, improves the Project revenue only marginally. Consequently,

this shows that the financial model is robust and it can be concluded that the Project is not a

financially attractive investment without CDM.

Impact of CDM Revenue

CDM has been in an integral part of MEN‟s plans for the Project. MEN pursued CDM since August

2006 through consultation with MUS well before the company concluded an agreement with the

technology supplier GE Jenbacher.

Although an ERPA has not been concluded, CDM revenue is expected to increase the Project returns

to a level above the benchmark. The company‟s board of directors approved the investment on the

condition that the Project be pursued as a CDM project activity.

MEN‟s management believes that the CDM will assist the Project not only with additional revenues

from the sale of CERs, but also in giving the Project higher status and social recognition which will

help it ensure the uninterrupted supply of natural gas it requires for the continuation of the business.

Consistent with the “Tool for demonstration and assessment of additionality”, the Project‟s additionality

needs to be further demonstrated through a Common Practise analysis (Step 4).

Step 4. Common practise analysis

This project development is unique as it involves an independent company investing in a small scale

power project using a less economic and cleaner fuel than the standard industry practise without




selling electricity to the public grid. This arrangement (or so called “ESCO”) is almost non-existent in

Indonesia‟s power sector.

Sub-step 4a. Analyze other activities similar to the proposed project activity:

Project with similar business arrangement & technology

An ESCO arrangement, as interpreted in the methodology, is an arrangement where an

independent third party invests in a power/thermal facility located within the users‟

manufacturing facilities and sells the generated outputs to designated users directly without

going through public installations (grid or steam pipeline).

While this type of arrangement exists, it is not common in Indonesia and to the best

knowledge of the project developer, none are employing co-generation technology, ie

providing power only through conventional or combined cycle system. These establishments

are:

PT Cikarang Listrindo, Cikarang, a 1000MW combined cycle power station

PT Kabil Industrial Estate, Batam, a 48MW combined cycle power station

The project developer, PT Manunggal Energy Nusantara is an independent small-scale

energy service company investing in the energy sector. It is a recently established company,

and this Project is the first installation at the users‟ location with limited market.

Sub-step 4b Discuss any similar options that are occuring

Both of the above-mentioned entities were established and operated by the management of

industrial estates – with a wider committed buyer and better economy of scale. Both facilities

were built at the time of economic booming prior to Asian economic crises in 1997 and

signed power purchase agreement with PLN and long-term gas contract with PGN early on

with favourable rate compared to the Project. Consequently, these entities are not confronted

with barriers that are being faced by the project developer to implement the Project.

At only 13.6MW with no public electricity interest and favourable gas rate, it is clear that

Project is well outside the league of the afore-mentioned facilities. At this scale, MEN‟s

decision to proceed with natural gas deemed the company activity against the mainstream

business practise which favours coal. Therefore the project activity has no similar activities.

It is pertinent to note, the government of Indonesia promotes the utilization of natural gas as

one of the indigenous energy sources. However, the promotion is currently bottlenecked by

lack of gas transmission infrastructure between producing region (Sumatra & Borneo) and the

consuming region (Java). Transmitted gas is prioritized for usage in industries supporting

agriculture, strategic petrochemical, and project supporting public power sectors - excess are

sold to industrial users and has been historically plagued with interruptions.

The lack of infrastructure is not likely to end soon as domestic natural gas price structure

favours priority industries, which does not include the textile industry, and remains a barrier

for investment in natural gas pipeline. Priority industries – which mainly comprise of the

largest consumers of natural gas, is allowed to purchase gas well below the international price

leaving investment in gas pipeline infrastructure unattractive9.

This supply uncertainty coupled with higher natural gas price per energy remains a barrier for

industry players to rely on natural gas as primary energy source and favours coal. In 2006, the

critical needs of electricity and presumably limited alternative pushed the government to

9 The Gas Gamble, GlobeAsia, March 2007




initiate a power acceleration programme which involves the installation of 20,000MW of

low-rank coal power plants across the archipelago. A large proportion of this will be located

on the industrial Island of Java where the Project is located. This programme, particularly in

Java, has gained momentum with many foreign and local entities enter agreement with the

government of Indonesia to proceed with this plan. Upon full implementation of this plan, the

possibility of lower electricity tariff is not remote creating a harder environment for natural

gas based electricity to compete.

As elaborated under Sub-Step 4a and 4b, similar activities can be observed but there are clear

distinctions between the project activity and the identified similar activities. As stipulated by the Tool

for demonstration and additionality assessment, the project activity is additional.

B.6. Emission reductions:

B.6.1. Explanation of methodological choices:

BASELINE EMISSIONS

B.1 Baseline emission associated with the displacement of residual oil for heat generation,

The Project will displace approximately 9.5tonnes per hour of steam at 8-10 bar pressure that is currently

generated using residual oil at the baseline scenario. The amount of energy that would have been required

to generate this steam in the absence of the project (ABEC) is calculated based on the amount of heat

generated by the cogeneration plant and the efficiency of the residual oil boiler in the baseline situation or

equation 3.2 of the baseline methodology.

Equation 1

Where:

Variable Description Unit

ABEC Amount of energy that would have been consumed to generate heat in

the user‟s residual oil boiler

TJ/yr

CHOR Amount of heat generated by the Project TJ/yr

Efficiency of the baseline boiler. unitless

The green house gas emissions (CO2, CH4, and N2O) associated with ABEC is calculated by multiplying

ABEC with the emission factor of green house gas G from the combustion of baseline fuel in this case:

residual oil ( ) and the green house gas global warming potentials ( ).

Equation 2


Baseline emissions from combustion of baseline fuel

(from CO2, CH4 and N2O)

t-CO2/yr

The amount of energy that would have been consumed to generate

steam in Argo Pantes‟ boiler

TJ/yr

Emission factor of green house gas g from the combustion of

baseline fuel.

t-gas /TJ




Global warming potential of greenhouse gas g. t-CO2

/t-gas

The emission factor from the baseline fuel (residual oil) is provided in the following table.

Table 6 – Emission Factors and Global Warming Potentials of greenhouse gases from residual oil

Emission factor from residual oil combustion CO2 CH4 N2O

Emission Factor of gas g in t-g/TJ, 77.4 0.003 0.0006

Global Warming Potential of gas g in t-CO2/t-g 1 21 310

Source for Emission Factor (default data used),

Table 2.2 Table 2.2 Table 2.2

2006 IPCC Guidelines for National

Greenhouse Gas Inventories

B.2 Baseline emission associated with grid-power displacement

The baseline emission from grid-power displacement is calculated based on the MWh produced by the

natural gas cogeneration unit multiplied by an emission coefficient, .

Equation 3


Baseline emission from electricity grid displacement t-CO2/yr

The amount of electricity generated by the project net of its parasitic

consumption.

MWh/yr

Emission factor of the electricity grid t-CO2

/MWh

Calculation of combined margin emission coefficient,

As the Project‟s generating capacity is 13.6MWe falls below the 15MWe small-scale threshold, the

emission coefficient is calculated as a combined margin (CM) emission factor as prescribed by

methodology ID following the method described according to the approved methodology ACM0002

(Version 06).

The combined margin emission factor consists of the combination of operating margin ( ) and build

margin ( ) emission factors set ex-ante and calculated as the weighted average of both factors.

Equation 4

Variable Description Unit Monitored*

Combined Margin CO2 emission factor of power

plants connected the Java-Bali grid in year y.

t-CO2/MWh N/R

Operating Margin CO2 emission factor of power

plants connected at the Java-Bali grid in year y

t-CO2/yr Yes

Build Margin CO2 emission factor of power

plants connected to the Java-Bali grid in year y

t-CO2/TJ No

(ex-ante)

The Project is located on the Island of Java, the relevant boundary for the calculation of is the

power plants connected to the Java-Bali grid.




1. Operating Margin Emission Coefficient ( )

The OM calculations were based on combination of PLN10

published data for year 2004 to 2005 and 2006

data obtained directly from PT PLN (Persero) P3B11

Jawa-Bali using the Simple OM approach. This is

appropriate as (a) no dispatch data could be obtained, and (b) low-cost/must-run resources constitute less

than 50% of the Java-Bali grid as shown in Table 7 below.

Table 7 - Percentage of Low/Cost Must Run Resources

Source Generating Capacity (GWhr)

PLN Version Source Type 2006 2005 2004

PLTA (Hydroelectric) Renewable 5,208 6,248 5,428

PLTU Non-Renewable 64,629 37,264 37,033

PLTG Non-Renewable 1,891 4,749 2,148

PLTGU Non-Renewable 26,939 26,185 25,476

PLTP (Geothermal) Renewable 6,500 2,870 2,988

PLTD Non-Renewable 108 161 94

Purchased from IPP12

Renewable 23,477 22,236

Total Generation (GWh) 105,274 100,954 95,403

% of Low Cost/Must Run 11% 9% 9%

The operating margin emission coefficient for each year (Y) is calculated using Equation 2 of ACM0002

adapted to data available from PLN website which has grouped the power plant according to its fuel

usage.

Equation 5


Operating Margin CO2 emission factor of power plants

connected at the Jawa-Bali grid in year Y

t-CO2

/MWh

Amount of fuel type j consumed by power plant connected to

electricity grid in year Y

kT

Net calorific value of fuel type j using default net calorific

value from Table 1.2 of 2006 IPCC Guideline

TJ/kT

CO2 emission factor of fuel type j obtained from Table 2.2 of

2006 IPCC Guideline

t-CO2/TJ

The generation capacity of power plant with non-renewable

fuel type j connected to the grid

MWh/yr

10 Indonesia State Electricity Company

11 Pengaturan dan Pusat Pengatur Beban (P3B) or Center for Electricity Control and Dispatch

12 Almost 20% of the total generated electricity is purchased by PLN from Independent Power Producers (IPPs)

using coal, geothermal, and hydro power plants. However PLN publication up to 2005 does not specify fuel

individual or specific consumptions from IPPs. For conservative estimate, these generation sources were added as

renewable energy – therefore does not have any impact to OM emission factor. The 2006 data includes this

information and therefore details are incorporated based on its generation source types.




Table 8 contains the Net Calorific Value (NCV) and CO2 Emission Factor (EFCO2) from each individual

fuel type used to calculate total emissions. NCV and EFCO2 Data for fuel oil is calculated as weighted

average between diesel oil and residue oil (marine fuel oil) based on 2006 fuel consumption data.

Table 8 - NCV and Emission Factor for Non-Renewable fuels

2006 IPCC Data NCV EF-CO2

TJ/kT T-CO2/TJ

Fuel Oil13

42.29 75.00

Coal14

25.5 96.1

Natural Gas 48 56.1

Table 9 shows the fuel consumptions from non-renewable generating sources connected to the Jawa-Bali

grid.

Table 9 - Fuel consumptions from non-renewable sources

Source Fuel Usage (kL)

2006 2005 2004

Fuel Oil

(kL=1m3)

High Speed Diesel 4,393,415 5,148,475 3,267,163

Industrial Diesel Oil - 14,288 9,586

Marine Fuel Oil 2,340,481 1,933,928 2,096,787

Total Fuel Oil 6,733,896 7,096,691 5,373,536

Coal (T) 26,978 15,014,433 13,425,337

Natural Gas (MMSCFD) 142,494 113,404 138,693

In order to estimate carbon emission for each type of fossil fuel, the fuel consumption data in Table 9 are

converted into its equivalent mass unit using its respective specific gravity: 840kg/m3 for diesel oil and

640kg/m3,15

for natural gas. The fuel consumption converted to mass unit is presented in Table 10.

Table 10 - Fuel consumption from non-renewable sources in mass unit

Fuel Type Fuel Usage (kT)

2006 2005 2004

Fuel Oil 5,656 5,961 4,514

Coal 26,978 15,014 13,425

Natural Gas 2,639 2,100 2,569

Total 35,274 23,076 20,508

The CO2 emission of each fossil fuel used in the electricity grid is calculated by multiplying the amount

of fuel used (Table 10) with the net calorific value and CO2 emission factor (Table 8). The result is

presented in Table 11 below.

Table 11 - Total CO2 emission from non-renewable sources

Fuel Type CO2 Emission (tCO2/yr)

2006 2005 2004

Fuel Oil 17,917,562 18,882,887 14,297,913

Coal 66,111,845 36,793,619 32,899,460

13 The NCV and EF of fuel oil is estimated as combined NCV or EF of diesel oil and marine fuel oil (residual oil)

based on its usage proportionality for the most recent year (in 2005)

14 The NCV of coal is estimated based on sub-bituminous mid-rank coal with calorific value of 6,100kcal/kg which

makes the large proportion of available coal in Indonesia.

15 Calculated using ideal gas at standard temperature and pressure, assuming 100% methane composition




Natural Gas 7,106,003 5,655,320 6,916,466

Total CO2 Emission (t-CO2) 91,135,409 61,331,826 54,113,840

The Simple OM CO2 Emission Factor for the electricity grid can be calculated by dividing the total CO2

emission from fossil fuel usage shown in Table 11 by the power generated from non renewable sources.

The results for individual year are shown Table 12. The calculated three years average OM emission

factor is 0.902t-CO2/MWh.

Table 12 - Ex-ante Operation Margin Emission Factor

Operating Margin 2005 2004 2003

Total CO2 Emission (t-CO2) 91,135,409 61,331,826 54,113,840

Total Power Generated (MWh) 105,274,140 100,954,150 95,403,210

Power from Renewable Energy (MWh)

Hydroelectric 5,207,670 6,248,000 5,428,220

Geothermal 6,499,760 2,870,000 2,988,240

Renewable 0 23,477,000 22,236,000

Total Renewable 11,707,430 32,595,000 30,652,460

Power from non-Renewable Sources (MWh) 93,566,710 68,359,150 64,750,750

Operating Margin Emission Factor (t-CO2/MWh) 0.974 0.897 0.836

Average for 3 years (t-CO2/MWhr) 0.902

2. Build Margin Emission Coefficient ( )

ACM0002 allows project developer to choose between Option 1 and Option 2 to calculate Build Margin.

Based on the consideration of limited access to reliable data, Option 1 is selected.

Option 1 calculates ex-ante build margin based on sample group m that consists of either:

(a) five power plants that have been built most recently, or

(b) power plant capacity additions the comprise 20% of the system generation that have been built most

recently

The methodology mandated to use whichever option that comprise the larger annual generation, as such

Option 1-b is deemed appropriate as the most recent five power plants only has total contribution of only

8.79% as shown in Table 13. The table lists the sample group m power plants from the most recent

(Cilegon), individual power plants fuel consumptions, and 2006 generations and its % contribution to the

total electrical generations from all power plants connected to Java-Bali grid.

Based on information provided by PT PLN (Persero) P3B, the most recently built power plant in the

Jawa-Bali grid and its generation output in 2006. The table lists power plants from based the most

recently installed (Cilegon).

Table 13 - Sample group m power plants

Sample group m power plant Fuel Type and

Consumptions

Cumulative generation

per total generations of

all power plants in the

Java-Bali grid (%)

Annual generation in

2006 (MWh)

Cilegon Gas 0.73% 773,676

1,948 kT

Tanjung Jati B Coal 4.55% 4,013,074

1,887 kT

Cilacap Coal 6.35% 1,901,659

965 kT

Muara Tawar 3-4 Fuel oil 7.91% 1,641,877




489kT

Wayang Windhu Geothermal 8.79% 922,299

No fossil fuel

Paiton PEC Coal 17.77% 9,451,482

4,556kT

Jawa Power Coal 26.74% 9,446,179

4,520kT

Total annual generation of power plant in sample group m 28,150,245

Total annual generation of all power plant in the Java-Bali grid 105,274,140

The build margin is calculated using equation analogous to Equation 5 of this PDD based on the selected

sample group m and information provided in Table 8. Table 14 shows the CO2 emission associated with

individual power plants in sample group m. The build margin emission factor is calculated to be

1.132tCO2/yr.

Table 14 - CO2 Emissions from sample group m power plants

Sample group m power plant Fuel Type and Consumptions 2006 CO2 Emissions

Cilegon Gas 18,041

1,948 kT

Tanjung Jati B Coal 4,624,359

1,887 kT

Cilacap Coal 2,365,099

965 kT

Muara Tawar 3-4 Fuel oil 1,549,790

489kT

Wayang Windhu Geothermal 0

No fossil fuel

Paiton PEC Coal 11,188,819

4,556kT

Jawa Power Coal 11,076,927

4,520kT

Total CO2 emission of power plants in sample group m (tCO2) (A) 30,823,037

Total annual generation of power plants in sample group m (MWh) 28,150,245

Total renewable energy generation in sample group m (MWh) 922,299

Total non-renewable energy generation in sample group m (MWh) (B) 27,277,946

Build margin emission factor (tCO2/MWh) = (A)/(B) 1.132

Combined Margin (CM) Emission Factor of the grid (

As elaborated above, the grid operating margin emission factor and build margin emission factor are

calculated and set ex-ante as 0.902t-CO2/MWh and 1,132t-CO2/MWh respectively. Using Equation 4,

the emission factor of the electricity grid is calculated as 1.017t-CO2/MWhr.

PROJECT EMISSIONS

The combustion of natural gas emits CO2, CH4, and N2O in the exhaust gas. Consistent with the

methodology, the emission resulting from the natural gas combustion is counted as a source of project

emission and calculated as the amount of energy from natural gas consumption required for the Project

activity multiplied with the gas emission factors and global warming potentials.




In order to be consistent with monitoring implementation procedure16

, the amount of energy from natural

gas for the cogeneration is further broken down in terms of from the volume of natural gas consumption

multiplied by its density and net calorific value.

Equation 6


Project emission from natural gas combustion t-CO2/yr

The amount of natural gas consumed for the project activity m3/yr

Specific gravity of natural gas kg/m3

Net calorific value for natural gas TJ/t

Emission factor of green house gas g from the combustion of natural

gas

t-g/TJ

Global warming potential of greenhouse gas g. t-CO2/t-g

The emission factor for each gas from the Project‟s fuel (natural gas) is provided in the following table.

Table 15 – Emission Factors and Global Warming Potentials of greenhouse gases from Natural gas

Emission factor from natural gas combustion CO2 CH4 N2O

Emission Factor of gas G in t-g/TJ ,

56.1 0.001 0.0001

Global Warming Potential of gas g in t-CO2/t-g ,

1 21 310

Source for Emission Factor (default data used) Table 2.2 Table 2.2 Table 2.2

2006 IPCC Guidelines for National

Greenhouse Gas Inventories

LEAKAGE EMISSIONS

The methodology requires methane from the production, processing, transmission, storage and

distribution to be considered as leakage emission. The highest possible methane emission factors from

these activities in non-OECD nations are used (Table 4.2.5 from 2006 IPCC Guideline) and tabulated

below.

Table 16 - Methane emission factor from natural gas production & distribution activities

Activity (k) Methane Emission Factors in Gg/10^6m3 of gas delivered

(totalled from fugitive & venting when applicable)

1 Gg = 1,000tonnes

Gas Production 0.024

Gas Processing (Sweet gas) 0.003528

Gas Transmission & Storage 0.001898

Gas Distribution 0.0025

The leakage emissions is calculated by multiplying the amount of natural gas consumed (in m3/yr) and

the emission factor for each activity (k) listed in Table 16

16 Natural gas consumption is procured in the unit of volume rather than energy for this Project




Equation 7


LE Leakage emissions from production, processing, transmission,

storage, and distribution of natural gas

t-CO2/yr

VNG The amount of natural gas consumed for the project activity m3/yr

kMEF Methane emission factor from activity k Gg/m3

EMISSION REDUCTION

The emission reduction is calculated as the difference between the baseline emissions and the sum of the

leakage and project activity emissions.

Equation 8


Baseline emissions from baseline fuel (residual oil) combustion

(from CO2, CH4 and N2O)

t-CO2/yr

Baseline emission from electricity grid displacement t-CO2/yr

Project emission from natural gas combustion t-CO2/yr

Leakage emissions from production, processing, transmission,

storage, and distribution of natural gas

t-CO2/yr

B.6.2. Data and parameters that are available at validation:

Data / Parameter:

Data unit: Fraction

Description: Efficiency of baseline boiler

Source of data used: Methodology default value

Value applied: 90%

Justification of the

choice of data or

description of

measurement methods

and procedures actually

applied :

Any comment:

Data / Parameter: Data unit: TJ/tonnes

Description: Net calorific value of natural gas used for the project activity

Source of data used: Pertamina gas data

Value applied: 45.5 TJ/k-tonnes


choice of data or

description of

measurement methods





applied :

Any comment:

Data / Parameter: Data unit: kg/m3

Description: Specific gravity of natural gas

Source of data used: Gas supplier, PGN or Pertamina

Value applied: 0.6538kg/m3


choice of data or

description of

measurement methods


applied :

Any comment:

Data / Parameter:

Data unit: t-CO2/t-g

Description: Global warming potential of gas G

Source of data used: IPCC

Value applied: CO2 = 1

CH4 = 21

N2O = 310


choice of data or

description of

measurement methods


applied :

Any comment:

Data / Parameter:

Data unit: t-G/TJ

Description: Emission factor of greenhouse gas G from combustion of residual oil

Source of data used: Table 2.2, 2006 IPCC Guideline for National Greenhouse Gas

Inventories

Value applied: Combustion of residual oil

CO2 emission factor = 77.4t-CO2/TJ

CH4 emission factor = 0.003t-CH4/TJ

N2O emission factor = 0.0006t-N2O/TJ


choice of data or

description of

measurement methods


applied :

Any comment:

Data / Parameter:

Data unit: t-G/TJ

Description: Emission factor of greenhouse gas G from combustion of natural gas in

the Project plant




Source of data used: Table 2.2, 2006 IPCC Guideline for National Greenhouse Gas

Inventories

Value applied: Combustion of residual oil

CO2 emission factor = 56.1t-CO2/TJ

CH4 emission factor = 0.001t-CH4/TJ

N2O emission factor = 0.0001t-N2O/TJ


choice of data or

description of

measurement methods


applied :

Any comment:

Data / Parameter:

Data unit: Gg/m3 or 1,000 tonnes/m3

Description: Methane emission factor from activity k

Source of data used: Table 4.2.5 2006 IPCC Guideline

Value applied: 0.024 for gas production

0.003528 for gas processing (sweet gas)

0.001898 for gas transmission and storage

0.0025 for gas distribution


choice of data or

description of

measurement methods


applied :

The above data totalled the fugitive and venting emission factor where

applicable and represent the upper end of emission in non-OECD

nation.

Any comment:

B.6.3 Ex-ante calculation of emission reductions:

BASELINE EMISSIONS

Baseline Emission from the Combustion of Baseline Fuel,

The project activity will displace approximately 9.8 tonnes per hour of saturated steam at 8 bar pressure

with heating value of 2,768kJ/kg17

. Based on the projected operating hours of 8,000 hours per year, the

generated steam is equivalent to 210TJ/yr.

The amount of energy required to generate the same amount of steam in the baseline boiler with default

efficiency of 90% is estimated as 233.7TJ/yr. Using the emission factor for green house gas CO2, CH4,

and N2O from residual oil combustion shown in Table 6, the emissions associated with the combustion of

avoided baseline fuels are calculated to be: 18,146t-CO2/yr.

17 Based on enthalpy of saturated steam at 8 bar




Baseline emission from grid-electricity displacement ( )

Based on 90% expected loading, operating hour of 8,000hr per year, maximum capacity of 13.61MWe

and 3% electrical consumption, the Project is expected to deliver about 95,052MWh/yr.

Using the calculated grid emission factor set ex-ante as 1.017tCO2/yr, the baseline emission from grid-

electricity displacement is 96,668t-CO2/yr

PROJECT EMISSION

Each gas engine is designed to consume 614m3/hr. With approximated operating hour of 8,000hr per year

the natural gas consumption for the five engines is totalled to 24,560,000m3 annually.

Gas specification sheets from the gas company stated that the natural gas has specific gravity of

0.6538kg.m3 and net calorific value of 0.0455TJ/t. Based on these data, and emission factor of natural gas

from IPCC shown in Table 15, the emissions from natural gas consumption is calculated as follow:

Annual natural gas consumption:

Emissions from natural gas consumption:

LEAKAGE EMISSION

Based on the gas activity coefficient data presented in Table 16, the methane emission (leakage) factor is

calculated as follow:

With calculated annual consumption of 24,560,000m3 of natural gas per year, the leakage emission

associated with natural gas production, processing, transmission and storage activities are calculated as

follow:

B.6.4 Summary of the ex-ante estimation of emission reductions:

Source Parameter Description Calcualted

Ex-Ante Values

(t-CO2/yr)

Baseline Baseline emission associated with combustion of 18,146




avoided residual oil

Baseline emission associated with the avoided grid

electricity

96,668

Total baseline emission 114,814

Project Project emission associated with the combustion of

natural gas for project activity

41,025

Leakage emission associated with natural gas

production, transmission, distribution, and storage

14,828

Total project emission 55,853

Total emission reduction 58,961

B.7 Application of the monitoring methodology and description of the monitoring plan:

B.7.1 Data and parameters monitored:

Data / Parameter: CHOR

Data unit: TJ/Yr

Description: Amount of heat recovered by the project waste heat boiler as

steam.

Source of data to be used: Combination of monitoring and calculation

Value of data applied for the

purpose of calculating

expected emission

reductions in section B.5

It is assumed that the steam is at saturated condition at 8 bar with

enthalpy of 2,767kJ/kg and flowrate of 9.5tonnes per hour or

210.33TJ/yr

Description of measurement

methods and procedures to

be applied:

1. Monitoring of the temperature (degC), pressure (kPa), and

flowrate (kg/year) of steam generated by the Project

2. Calculate enthalpy of steam at the monitored temperature

and pressure using accepted steam table (H) in kJ/kg

3. Calculate annual heat output of the Project by multiplying

enthalpy and steam flowrate.

QA/QC procedures to be

applied:

1. Flowrate, Pressure & Temperature monitoring gauge will be

calibrated using international standard to have a maximum

error of 1%

2. Steam enthalpy data will be sourced from acceptable

engineering data.

3. Data must be verified with sales invoices/receipt by Argo

Pantes.

Any comment: Data is recorded automatically by a computerized system able to

store information for up to 3 months. But information will be

logged on daily basis for a weekly emission reduction monitoring

report.

Data / Parameter: AOH

Data unit: Operating hours of the power plant

Description: hr/yr

Source of data to be used: Power plant on/off switch from all 5 gas engines



expected emission


8,000hour per year.



The system is equipped with software applications that allow

monitoring of the plant operation. Records of this application




be applied: will be kept as basis for counting the operation hour of the gas

engines.


applied:

The monitoring & record data transfer is automated and therefore

error is minimal




report.

Data / Parameter: ;

Data unit: t-CO2/MWh

Description: Operating Margin (OM) CO2 emission factor of power plant

connected to the Java-Bali electricity grid in year y

Build Margin (BM) CO2 emission factor of power plants

connected to Java-Bali electricity grid in year y

Source of data to be used: PLN published data



expected emission


0.936t-CO2/MWh



be applied:

No measurement required. Data is obtained based on analysis of

PLN published information


applied:

Not required

Any comment: Data is calculated on annual basis.

Data / Parameter: CEO

Data unit: MWh/yr

Description: The amount of electricity generated by the project net of its

parasitic consumption.

Source of data to be used: Electricity meter



expected emission


95,052MWh based on

90% load,

8,000 operation hour; and

gas engine capacity of 13.6MW



be applied:

Record is collected quarterly from cumulative electricity meters

from individual engines


applied:

Electricity meters are subject to laboratory standard calibration

with error less than 1%

Data is cross checked with sales invoices to Argo Pantes, Argo

Fajar and Argo Beni on monthly basis




report.

Data / Parameter: VNG

Data unit: m3/yr

Description: The amount of natural gas consumed by the project acitivity

Source of data to be used: Individual gas meters attached to the engine.






expected emission


29,528,373m3/yr



be applied:

Data is obtained quarterly from the PGN gas meters


applied:

Gas meter is subject to laboratory calibration

Data is verified with payment receipt from PGN.




report.

B.7.2 Description of the monitoring plan:

Data Collection and Reporting Structure

Operational data relevant for emission accounting will be logged by operator on daily basis using a pre-

prepared log-sheet form part of the operator log book. The report will be signed and checked by an

Operational Manager who will compile the report on weekly basis to determined:

thermal delivery from individual gas engine;

electrical output of individual gas engine; and

gas consumption of individual gas engine.

On monthly basis, the Operational Manager consolidates the above data, and cross-checked them against

receipt from user and sales invoice from gas suppliers. The compiled information is summarized into an

Emission Reduction Delivery Report (ERDF) to be submitted to MEN‟s General Manager who will issue

a six-monthly ERDF following an audit in reporting procedure and calibration report. This report will be

part of the Annual Monitoring Report that will be verified by the DOE.

Calibration Procedure

The instrumentations installed are new and has been calibrated to international standard before

commissioning. Regular calibration will be performed on regular basis during the annual maintenance

shut-down at the end of first year and subsequent years to all identified instrumentations up to error level

up to 1% or less for the electricity meter.

Every end of maintenance shut-down, a Calibration Report Status is composed to list all CDM-related

instruments, their details, calibration status and expected error. This calibration report status will be

subjected to checking by MEN‟s General Manager at the issuance of six-monthly ERDF and will be

provided as an attachment in the Annual Monitoring Report that will be verified by the DOE.

Archiving of Data

All emission reduction related data and reports will be archived for up to 3 years from the end of each

crediting period.

B.8 Date of completion of the application of the baseline study and monitoring methodology and

the name of the responsible person(s)/entity(ies)

Clean Energy Finance Committee

Mitsubishi UFJ Securities Co., Ltd.

Tokyo, Japan

Tel: +81 3 6213 6331

Junji Hatano

Email: [email protected]




The baseline information was completed in May 2007

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:

01/02/2007

C.1.2. Expected operational lifetime of the project activity:

21 years

C.2 Choice of the crediting period and related information:

C.2.1. Renewable crediting period

C.2.1.1. Starting date of the first crediting period:

18/08/2007 or immediately after registration

C.2.1.2. Length of the first crediting period:

7 years

C.2.2. Fixed crediting period:

C.2.2.1. Starting date:

N/A

C.2.2.2. Length:

N/A




SECTION D. Environmental impacts

D.1. Documentation on the analysis of the environmental impacts, including transboundary

impacts:

The Project is not expected to have adverse environmental impacts and therefore is not required to

prepare an Environmental Impact Analysis (EIA) under the applicable regulation.

The Project has obtained approval for the necessary environmental actions documentations (UPL/UKL)

from the Environmental Agency of the City of Tangerang (or Dinas Lingkungan Hidup Kota Tangerang)

in December 2006 with approval registration number 660.1/1469-APDL.

The documents detail possible environmental impacts that may arise from the project activity before

construction, after construction, and after operation as well as the necessary mitigation.

D.2. If environmental impacts are considered significant by the project participants or the host

Party, please provide conclusions and all references to support documentation of an environmental

impact assessment undertaken in accordance with the procedures as required by the host Party:

The Project is not expected to result in adverse environmental impact. Possible impacts arising from the

project activity will be further assessed in the sustainability analysis required to obtain the letter of

approval from the Indonesian government.

SECTION E. Stakeholders’ comments

E.1. Brief description how comments by local stakeholders have been invited and compiled:

The project participant hosts a stakeholder consultation meeting at the Argo Pantes office in Tangerang

on December 27th 2007. Invitations were distributed to various institutions including local environmental

agencies (BAPPEDAL), National Commission for Clean Development Mechanism (Komnas MPB or

DNA), industrial users to the Project, other industrial users located within Cikokol area, as well as

community members through the neighbourhood units (RT).

The meeting was attended by 21 people excluding

representative of industrial users to the Project and

management of MEN.

The meeting was opened by Head of Production of PT

Argo Pantes (Mr. Santo) and followed by an opening

statement by Mr. Prasetyadi Utomo from Komnas MPB.

Project information was presented by Mr. H. Soeyoto, the

Director of Manunggal Energi Nusantara.

E.2. Summary of the comments received:

The following summarized the inquiries raised during the stakeholder consultation.

Mr. Maman, representing the Tangerang City environmental Agency (Dinas KLH) inquires on the

Project‟s impact on waste, traffic, and employment opportunity to surrounding communities. He also




raised possibility of the Project developer to retail electricity to the residential areas at a rate lower or at

least equal to PLN.

To the first concern, MEN responded that the project construction will have a limited impact as it

will renovate an existing power house in Argo Pantes instead of erecting a new building for the

Project equipment. Impact to traffic during this time will also be minimal as the major equipment

would be assembled in Austria and delivered in three shipments. During operation, the project

needs water to operate its boiler, but there will be no incremental water usage from what is

already being consumed by Argo Pantes. Waste is expected to be generated by the project in the

form of the oil-based lubricant that is necessary to maintain the major equipments. The volume is

very small to raise any environmental concern and would be handled by the maintenance

company. Additional domestic waste water will be generated from the additional 20skilled

workers that will be hired to maintain the project‟s continuous operation. During the construction

time, limited workers are required and handled by the construction company.

To the second concerns, MEN responded by stating that this Project is the first in MEN‟s

portfolio and further development would be upon the Project‟s success. Unlike PLN, MEN do not

receives any subsidy or incentive from the Indonesian government to develop transmission

network for electricity retail. However, upon the industrial users relinquishing their PLN

utilization, more electricity would be available for the public.

Mr. Aris Munandar representing the Banten Province environmental agency (BAPPEDAL) requests

clarification on the Project‟s output dispatch status to the industrial users; the project capital investment;

and the impact of avoiding coal to the neighbourhood.

MEN‟s clarifies that industrial users will use the Project‟s output as the primary energy source and will

continue to use PLN as energy back-up in the first year. Upon the Project‟s successful performance, the

industrial users may decide to disconnect from PLN. The Project‟s capital investment is expected to be

circa USD12,5million. On the issue of coal avoidance, MEN‟s stated that the positive impacts are

reduction of potential air pollution and elimination of traffic for the transportation of coal. The economic

impact will be felt by both coal suppliers and PLN, not to surrounding community.

Mr. Mamang, Tangerang City government representative (Camat Tangerang) raised the issue of

completion of permits on which MEN responded by stating that the company activity has obtained the

necessary permit for general electricity provision from Serang District Mineral & Energy agency.

E.3. Report on how due account was taken of any comments received:

The Project and MEN‟s explanations were well accepted by the representative of environmental agencies

and there are no due accounts from the comments received during the stakeholder meeting. Community

members and local government representatives agree that the Project will have positive contribution to

the environment.




Annex 1

CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY

Organization: PT Manunggal Energi Nusantara

Street/P.O.Box: Jl. Gatot Subroto Kav. 22

Building: 2nd

Floor Wisma Argo Manunggal

City: Jakarta

State/Region: DKI

Postfix/ZIP: 12930

Country: Indonesia

Telephone: +62 (21) 252 0065

FAX: +62 (21) 252 0029

E-Mail: [email protected]

URL:

Represented by: H. Soeyoto

Title: Director

Salutation:

Last Name: Soeyoto

Middle Name:

First Name: H.

Department:

Mobile:

Direct FAX:

Direct tel:

Personal E-Mail: [email protected]

Organization: Mitsubishi UFJ Securities Co., Ltd.

Street/P.O.Box: 2-5-2 Marunouchi, Chiyoda-ku

Building: 2F, Mitsubishi Building

City: Tokyo

State/Region:

Postfix/ZIP: 100-0005

Country: Japan

Telephone:

FAX:

E-Mail:

URL: http://www.mitsubishi-sec.co.jp/english_fs.html

Represented by:

Title: Chairman, Clean Energy Finance Committee

Salutation: Mr.

Last Name: Hatano

Middle Name:

First Name: Junji

Department: Clean Energy Finance Committee

Mobile:

Direct FAX: +81 3 6213 6331

Direct tel: +81 3 6213 6175

Personal E-Mail: [email protected]

http://www.mitsubishi-sec.co.jp/english_fs.html




Annex 2

INFORMATION REGARDING PUBLIC FUNDING

The Project does not involved any public funding

Annex 3

BASELINE INFORMATION

Refer to Section B.4

Annex 4

MONITORING INFORMATION

Refer to section B.7.2

Annex 5

OTHER INFORMATION

Annex 5.1 Energy savings resulting from implementation of Project

Energy Consumption Before the Project

Prior to the Project, heat is generated by means of residual boiler with maximum efficiency of

90%. Electricity is purchased from the grid. The following energy consumption is calculated

based on maximum electrical generation efficiency of 40% - without accounting for transmission

loss.

Table 17 shows the basis and assumptions taken to calculate energy input as well as calculation

result.

Table 17 - Baseline Energy Input

Baseline

Heat Generation (Residual Boiler) unit Value

1 Steam Enthalpy MJ/t 2767.5

2 Flowrate t/hr 9.5

3 Operation hour hr/yr 8000

4 Residual boiler efficiency fraction 0.9

Energy Input for Heat Generation TJ/yr 233.7

Electrical Generation (Grid electricity) unit Value

1 Electricity Output MW 11.88


3 Electrical generation efficiency (Max) fraction 0.4

Energy Input for Electricity Generation TJ/yr 855.36

Total Energy Input TJ/yr 1089.06

Energy Consumption After the Project

After the Project, no additional energy is required to generate steam as this will be generated

using the exhaust of the gas engine. Based on manufacturer specification, each gas engine needs

6,498kW to generate 2,722kW of electricity. This means that the electrical generation efficiency

of each gas engine is 41.8%.

Table 18 shows the basis and assumptions taken to calculate energy input as well as calculation

result.




Table 18 - Project's Energy Consumption

ProjecT

Heat Generation (Waste heat boiler) unit Value

Energy Input for Heat Generation TJ/yr 0

Electrical Generation (Natural Gas Engine) unit Value

1 Electricity Output MW 11.88


3 Electrical generation efficiency (Max) fraction 0.418

Energy Input for Electricity Generation TJ/yr 818.52

Total Energy Input TJ/yr 818.52

Total energy savings from implementation of Project

Without the Project, it is estimated that 1,089TJ/yr of energy is required to generate electricity and heat

equivalent to that generated by the Project. The Project improves the energy generation efficiency and

requires only 818.52TJ/yr. This means that the project implementation reduces the energy consumption

by nearly 25%.

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