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Draft Final Report

PROMOTION OF RENEWABLE ENERGY,ENERGY EFFICIENCY AND GREENHOUSE GAS

ABATEMENT (PREGA)

Philippines

Dual-Fired Cogeneration in a Distillery

A Pre-Feasibility Study Report1

July 2006

1 Prepared by the PREGA National Technical Experts from CPI Energy Philippines, Inc.(Samuel C. Custodio, Enrique O. Tongco, and Cindy C. Tiangco).



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1. Executive Summary

In a period of high-energy prices largely brought about by increasing oil prices, energy conservation

and energy efficiency measures become imperative and urgent. The Philippine government has

stepped up and doubled its efforts in curtailing a crisis. Cogeneration, or the simultaneous production

of electricity and process steam or heat from a single unit, is an energy efficient technology that

promises a financially viable and environment-friendly option in supply-side energy management. This

study shows that while this technology is proven and its benefits are numerous, barriers such as high

investment costs have hindered its diffusion.

Commercial and industrial establishments account for more than 50% of the country’s electricity

consumption and this provides a corresponding large potential for energy savings and greenhouse gas

abatement. In the Philippine Energy Plan 2005 Update, the National Energy Efficiency and

Conservation Program of the Department of Energy aims to attain aggregate energy savings of 240.8

million barrels of fuel oil equivalent (MMBFOE) from energy efficiency projects within the next tenyears with a corresponding equivalent emission avoidance of 61,977 kilotons carbon dioxide (kTCO2).

This translates to around USD 831.9 million average annual savings (based on a USD 35.5 per barrel

crude oil price) and around 832 MW of deferred power generating capacity. 2 With the crude oil price

hovering at over USD 60 per barrel these figures are now almost doubled.

Cogeneration is an appropriate EE technology for the food industry, which invariably requires both

heat and power in its processes. While the cogeneration project proposed here still uses fossil fuel, its

benefits come from producing cheaper self-generated power, reduced electricity consumption from the

Luzon grid, and the reduced bunker fuel oil consumption through optimizing the use of biogas from

the facility’s wastewater treatment plant. In the evaluation of the project’s greenhouse gas

abatement potential, however, the main consideration is the fuel mix of the grid electricity. Current

power generation sources and recent capacity additions, however, are either RE-based or natural gas

based power plants. This study has found out that this shift in the operating and build margins has

eliminated the GHG abatement potential of oil-based cogeneration projects. Cogeneration based on

renewable energy is expected to offer considerable carbon credits and is therefore recommended.

The Project studied entails the construction and installation of a dual-fired (BFO and biogas-fired)

cogeneration plant at Absolut Chemicals Inc. (ACI). ACI sources its electricity from the Batangas

Electric Cooperative I (BATELEC I). Currently, Absolut Chemicals, Inc. (ACI) has three fire tube

boilers, one with a rating of 600 BHP, another boiler with a rating 500 BHP and a third boiler with a

rating of 350 BHP. The first two boilers are the main boilers used in their daily operations, while the

third serves as the stand-by boiler, in case either of the main boilers would need to be shut down. This

would mean that, if the reserve boiler would run in place of either one of the main boilers that are in

2 Philippine Energy Plan 2005 Update, DOE (2005)



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operational, the operation would incur a reduction in capacity of between 150 to 250 BHP. This is a

rating down of 14% to 23%, which is already quite substantial.

This year, however, ACI has experienced more than seven percent (7%) increase in production from

last year’s average and the three boilers are now running to produce the required steam. From the

2004 average steam requirement of 17 tons per hour, it has increased to 18.2 tons per hour. Clearly,

the reliability issue is becoming a bigger concern for the management and there is a need to address

the issue.

One alternative would be to procure a new 800-BHP fire tube boiler to serve as the main boiler

together with the 500-BHP boiler, producing the required 18.2 tons of steam per hour. The old 600-

BHP boiler would serve as a back-up boiler, in which case the rating down of steam production would

be less than 7%. The other alternative would be to use this opportunity to apply cogeneration. In the

cogeneration alternative, the company would procure a 900-BHP water tube boiler and turbine

generator, thereby producing both the steam requirements and generating the electricity

requirements of the plant. For brevity, we shall call the alternatives as Alternative A and Alternative B,

respectively.

The first alternative, without cogeneration, is taken as the baseline. The baseline emissions are the

emissions from BFO combustion and the equivalent emissions of grid electricity from the Philippines,

which in recent years have shifted from oil and coal to natural gas and geothermal energy sources.

The baseline emissions were calculated to be 33,731 tons CO2e per year. The project emissions are

the emissions from BFO combustion in the dual-fired cogeneration plant and calculated to be 34,254

tons CO2e per year. The resulting net emission reduction is therefore negative at -523 tons CO2e peryear.

For the financial and economic analyses, this pre-feasibility study assumes in-house financing for this

project that has a total capital cost of PhP62.9 Million. The company shall provide 15% of the

investment cost as equity while 85% will be borrowed from the Development Bank of the Philippines

(DBP) at a rate of 12%. The return on the company’s equity is at 20%. The weighted average cost of

capital is therefore 13.20%. For a ten-year crediting period, the FIRR, Financial NPV and EIRR without

carbon credits are 80.65%, PhP110.44 Million, and 114.67%, respectively. With the resulting increase

in project emissions, albeit small, the project is ineligible for carbon credits. The payback time for the

project is around fourteen (14) months.

The Clean Development Mechanism (CDM) was one of the several financing options considered for the

proposed project. However, project emissions were found to be higher than the baseline emissions

and therefore the project has no carbon credits. Benefits will likely be realized if the cogeneration



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plant will be run on renewable energy. A thorough study on this option is therefore recommended if

Absolut is inclined to pursue the project.

However, given its financial viability and economic benefits, the project is worth considering. This

pre-feasibility study has shown that as an energy efficient supply side option, cogeneration promises a

potential for energy savings wherein self-generated electricity is cheaper than grid-supplied power. If

the cogeneration is RE-based, environmental benefits and carbon credits will also be realized. Further

studies are therefore warranted.



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Table of Contents

1. Executive Summary

2. Location Map

3. Introduction

4. Background

4.1 Cogeneration and the Food Industry

4.1.1 Issues, Barriers and Constraints to Commercialization of

Cogeneration Technology

4.1.2 Relevant government policies and strategies

4.1.3 Relevant policies and strategies of the Asian Development Bank

4.2 Benefits of the Project

5. General Description of the Proposed Project

5.1 Project Overview

5.2 Rationale and Objectives

5.3 Project Partners and Implementing Agencies

5.4 Technology-transfer

5.5 Product

6. Project Implementation

7. Project Baseline and GHG Abatement Calculation

7.1 Current production and delivery patterns

7.2 Flowchart of the Current production and delivery patterns

7.3 Project baseline

7.4 Project boundary and monitoring domain

7.5 Baseline methodology and calculation of the baseline emissions

7.6 Total Project GHG Emissions

7.7 Net emission reduction

7.8 Additionality

8. GHG emission reduction monitoring and verification

8.1 Data Requirements

8.2 Methodology used for data collection, monitoring and reporting

8.3 Estimates of costs for monitoring and verification

9. Financial Analysis

9.1 Overall Costs Estimates

9.2 Project Financial Analysis

9.2.1 FIRR and NPV without CO2 credits

9.2.2 The incremental cost of carbon abatement

9.3 The Financing Plan

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9.4 Financing Mechanisms to Promote Cogeneration

10. Economic Analysis

10.1 Poverty reduction impact

10.2 Social and gender

10.3 Economic Analyses

10.3.1 The EIRR and NPV without CO2 credits

10.4 Sensitivity Analysis

11. Stakeholders’ Comments

12. Key factors impacting project & baseline emissions

12.1 Project Uncertainties and Risks

13. Conclusions and Recommendations

14. References

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List of Abbreviations

ADB Asian Development Bank

ACI Absolut Chemicals Inc.

BATELEC I Batangas Electric Cooperative I

BFO Bunker Fuel Oil

CAA Philippine Clean Air Act of 1999

CDM Clean Development Mechanism

CER Certified Emission Reduction

CHP Combined Heat and Power

CPIE CPI Energy Phils., Inc

DBP Development Bank of the Philippines

DMC Developing Member Country

DOE Department of Energy

DSM Demand-side Management

EE Energy Efficiency

EIRR Economic Internal Rate of Return

EPC Engineering-Procurement-Construction

ESCO Energy Service Company

FIRR Financial Internal Rate of Return

GHG Greenhouse gas

IPCC Intergovernmental Panel on Climate Change

WACC Weighted Average Cost of Capital

MMBFOE Million Barrels of Fuel Oil Equivalent

MW Megawatt

NEDA National Economic and Development Authority

NPV Net Present Value

O & M Operating and Maintenance

ODPS One-Day Power Sale

PA 21 Philippine Agenda 21

SD Sustainable Development

WESM Wholesale Electricity Spot Market



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2. Location Map

Plant Location: Lian, Batangas

3. Introduction

Electricity occupies a large, if not the major, portion in the production cost of a manufacturing

industry. The price of electricity in the Philippines continues to be among the highest in Asia.

Furthermore, industries are facing a critical period due to increasing price competition, stringent

environmental regulations and limited capital. Cost reduction, system and equipment upgrades and

increasing energy efficiency are considered essential measures for long-term viability. There is then a

renewed interest in cogeneration, an efficient and environmentally benign technology that is widely

applied in developed countries but still has to enter mainstream engineering design in developing

countries.

The subject company, Absolut Chemicals Inc. (ACI), is currently sourcing its electricity from the

Batangas Electric Cooperative I (BATELEC I) at PhP7.20 per kilowatt-hour (kWh) and based on its

most recent 2005 monthly utility bills, its peak demand is over 1,200 kW. It has 3 fire tube boilers, a

600 BHp, 500 BHp and 350 BHP boilers. The boilers supply a total of 18.2 tons per hour of steam at

6.5 bars, and operate 8,400 hours per year. ACI also has two diesel generating sets (400 kW and 500



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1) Technological Issues

A UN ESCAP study indicates that using cogeneration overall efficiencies of as high as 92% are achieved

giving primary fuel savings of 35% compared to separate generation. Backpressure steam turbine

cogeneration systems achieve the highest overall efficiencies (84-92%), followed by gas turbine

systems (70-85%), and extraction-condensing steam turbine systems (60-80%).3

Because there is a demand for high-pressure quality steam to generate electricity at ACI the steam

turbine is utilized. The main advantages of the steam turbine system are the high overall efficiency,

high reliability and long working life. Moreover, the power-to-heat ratio can be varied. The correct

sizing of the cogeneration system involves identifying the potential for energy conservation and energy

efficiency projects and assessing likely changes in the site's future energy demand because maximum

system efficiency is achieved when the system is operating at full load.

2) Environmental Issues

One of the most important products of the combustion process is carbon dioxide, well known for its

contribution to the greenhouse effect and climatic change. However, where cogeneration replaces the

separate fossil fuel generation of electricity and heat, it reduces primary fuel consumption by about

35%. This means a similar reduction in CO2 emissions. Emissions of sulfur dioxide vary directly with

the sulfur content of the fuel. Diesel fuel and Bunker C fuel oil, however, do contain sulfur and, where

the sulfur content exceeds the limit set by the manufacturer, some form of fuel cleaning is necessary

prior to use. Oxides of nitrogen (NOx) are produced when burning any fuel in air. The level of NOx

emissions, however, is dependent on combustion conditions and particularly on temperature, pressure,combustion chamber geometry and the air/fuel mixture.

3) Financial Issues

Capital cost is the major issue in the diffusion of any energy efficient technology such as cogeneration.

Investment costs vary with the type of prime mover, the degree of sophistication of the automatic

monitoring and control system, the need for additional pollution abatement equipment or acoustic

protection, and the costs of site preparation, grid connection etc. This study shows that the required

investment capital for the cogeneration plant can be recovered from the savings in electricity costs in

less than two years. The simple payback achieved by cogeneration demonstration projects varies from

1 to 10 years with an average of 4.5 years.

4.1.2 Relevant government policies and strategies

3UN ESCAP (2000)



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The DOE continues to pursue an aggressive energy efficiency and conservation program aiming to (a)

increase participation of companies that manage energy consumption efficiently from the commercial,

industrial and transport sectors, as well as from the government sector without putting constraints on

productivity and services provided; (b) strengthen consumer understanding of energy use; (c)

encourage Energy Service Companies (ESCOs)4 to accelerate implementation of the program in the

commercial and industrial sectors; and (d) reduce GHG emissions as a result of improved energy

consumption. These programs are expected to attain aggregate energy savings of 240.8 MMBFOE

within the next ten years with a corresponding equivalent emission avoidance of 61,977 kilotons

carbon dioxide (kT CO2).5 These programs also enable establishments to comply with the provisions

and standards set by the Philippine Clean Air Act of 1999.

The Philippine president issued Administrative order No. 126 on August 13, 2005 directing the

enhanced implementation of the government’s energy conservation program. The DOE is currently

conducting energy audits of government establishments to assess their energy and fuel efficiencies

and ensure the full implementation of the EE program.

4.1.3 Relevant policies and strategies of the Asian Development Bank

Like DOE, the Asian Development Bank (ADB) has accorded importance to energy audits of energy-

intensive industries and to persuading such industries to adopt energy efficient technologies and

equipment knowing that industry accounts for over 55 per cent of the final energy consumption in

developing member countries (DMCs) such as the Philippines. ADB and the DOE will assist in the

promotion and establishment of ESCOs to undertake energy efficiency improvements in the premises

of consumers.

The ADB believes that the key to the success of programs to promote energy efficiency lies in a

combination of: (i) energy prices fully reflecting the long-run marginal cost (LRMC) of supply, border

prices and opportunity costs; (ii) legislation and enforcement of sound environmental standards

(covering all types of pollution) as well as building codes and appliance standards focusing on energy

efficiency; (iii) trade regimes and investment regimes that allow the easy flow of energy efficient

technology and goods; (iv) fiscal policies that penalize the production and import of energy-inefficient

goods and technologies and that reward the energy efficient ones; (v) evolution of energy efficient

national and regional standards for appliances and equipment, establishment of testing facilities and

introduction of labeling and truth-in- labeling requirements; and (vi) tax and other forms of incentives

for industries, households and commercial establishments to adopt energy efficient technology and

equipment. 6 ADB's program lending modality has achieved policy changes with the DOE

4ESCOPhil was organized on 1 October 2004 and incorporated on May 31, 2005. Mr. Antonio A. Ver, President and COO of CPI

Energy Phils., Inc, was elected ESCOPhil President.5

DOE, 20056

http://www.adb.org/Documents/Policies/Energy_Initiatives/energy_ini322.asp?p=policies



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implementing programs along these lines (except for the use of return on rate base instead of LRMC

to determine energy prices).

4.2 Benefits of the Project

The implementation of cogeneration systems will have positive long-term effects on the economy in

many ways. While the cogeneration project still uses BFO, the amount consumed is less than what it

would be with separate generation of process steam and electricity. Self-generated electricity will

replace Luzon grid electricity and was found out to be much cheaper than grid-supplied power. In

recent years, however, the operating margin and the build margin are dominated by natural gas and

geothermal energy, making oil-based cogeneration an unattractive option as a GHG Abatement

project. In light of these changes, RE-based cogeneration may offer greater benefits in efficiency and

GHG abatement. The introduction of state of the art technology will facilitate the development of new

and improved skills and expertise. These will be immediately applicable not only within the food

industry but also in other industries. In addition, the transition to the new technology will spur the

growth of the new industry of Energy Service Companies or ESCO’s.

During the project preparation there might be some negative impacts on the local environment due to

increased road traffic for material transportation purposes. Nevertheless there is potential, in the long

term, for upgrading infrastructure, which will benefit the whole local community and great potential

for poverty alleviation with the creation of new jobs in the local economy. Other benefits are

summarized below:

Poverty alleviation and other social benefits: (1) Job security and new jobs would have a positive

impact on the local community, (2) Improved performance of the company, and perhaps after EE

projects, long-term financial security of the operation, (3) Improved quality of life through wage

increases and income generation.

Gender equity: There would be no specific impact on gender equity; however, job creation could bring

employment for women and poverty alleviation elements could be designed to specifically target

women.

Macro-economic: (1) Increased industry competitiveness would improve economic performance and

could lead to a reduction in the national debt, (2) Help define investment priorities that meet

sustainable development goals, (3) Encourage and permit active participation of private and public

sectors.



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Micro-economic: (1) Improved factory performance and new jobs in electricity generation activity

increase economic status of local community, (2) For the factory, improved competitiveness, etc,

should bring economic benefit to owners, managers, employees and other stakeholders.

Energy related: (1) Project would develop a new approach to electricity generation and energy supply

to the factory, (2) Increased energy awareness and new energy saving measures would improve

energy performance of the factory.

Transfer of technology and financial resources: (1) Attract capital for projects that assist in the shift to

a more prosperous economy, (2) Investment is channeled into projects that replace old and inefficient

fossil fuel technology and create new industries in environmentally sustainable technologies, (3)

State-of-the-art technology would be introduced, possibly through the involvement of an equipment

supplier from Annex 1 countries, (4) New technical, managerial and organizational skills would be

introduced, possibly leading to other related improvements in the factory.

5. General Description of the Proposed Project

5.1 Project Overview

5.1.1 Title: Installation of a Dual-Fired Cogeneration Plant at Absolut Chemicals Inc.

5.1.2 Host Country: Philippines

5.1.3 Contact and Responsibility: MR. GERARDO TEE

Plant Manager

Absolut Chemicals Inc.

Brgy. Maruhatan, Lian, Batangas

Telefax no. (043) 215 2439

5.2 Rationale and Objectives

There are significant economic benefits to the long-term adoption of cogeneration technology as it

produces cheaper electricity and consumes less fuel than separate generation of steam and power.

The project aims to simultaneously generate process steam at 6.5 bar pressure and 1,200 kW of

electricity for the ACI plant in Lian, Batangas. It would require the installation of a high-pressure

water tube boiler and new steam generator equipment. This project will offset about 10.08 GWh(1,200 kW at 8,400 hours per year) of equivalent electricity yearly.

5.3 Project Partners and Implementing Agencies

With the project implemented through in-house financing, ACI shall require a loan facility from the

Development Bank of the Philippines to finance 85% of the project cost. An engineering-



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procurement-construction (EPC) contractor shall be selected according to the requirements and

bidding and selection process of the lending bank. An ESCO may undertake the EPC contract and

implement the project. The Asian Development Bank, the Department of Energy, and the Department

of Environment and Natural Resources (the CDM National authority) shall be consulted regarding

procedures and project implementation if CDM is considered.

5.4 Technology-transfer

The project will employ technology that is familiar to the ESCO but might be new technology for the

subject company. The ESCO or another stakeholder could participate in the project as equity partners

and gain the benefit from the emission credits. Some of the benefits shall be:

• State-of-the-art technology would be introduced, possibly through the involvement of an

equipment supplier from Annex 1 countries.

•

New technical, managerial and organizational skills would be introduced possibly leading toother related improvements in the factory.

5.5 Product

In 2004, ACI produced 45,000 liters/day of ethyl alcohol and consumed 200 to 240 Metric tons/day of

sugar cane molasses. Tanduay Distillers purchases 100% of ACI’s ethanol production.

6. Project Implementation

Project implementation will take a total of 20 months. The implementation schedule can be divided

into two (2) stages: pre-construction and construction. The pre-construction stage starts with the

submission of the feasibility report, preparation of tender documents, followed by loan negotiation,



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PROPOSED EPC SCHEDULE

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Prepare Tender Documents

Technical Concept / Basic Engineering

Loan / Financing Negotiation

Selection of Contractor and Negotiation

Negotiation and award of contract

Procurement & delivery of main engine

Detailed Engineering / Manufacturing

Construction Works

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

5 months

8 months

4 months

14 months

4 months

2 months

2 months

1 m

selection of contractor and finally the award of contract. This stage will require 10 months. The civil

works and construction stage starts after the contract award and detailed engineering. It will require

14 months to complete.

7. Project Baseline and GHG Abatement Calculation

The project involves the adoption of energy efficient cogeneration technology to provide electricity and

heat from a single unit. This technology displaces the electricity requirement from the grid while

supplying a substantial portion of the steam requirement of the company’s production process.

Current production and delivery patterns will not be changed as a result of the project. The project

boundary is the cogeneration plant equipment.

7.1 Current production and delivery patterns

Absolut Chemicals Inc (ACI) is a duly organized corporation existing under Philippine Laws, with

principal offices at 7th floor Allied Bank Center, 6754 Allied Bank Center, Ayala Avenue, Makati City.

The company has undergone a change of name from Century Distillery to Absolut Chemicals Inc

during its inception in 1990.

7.2 Flowchart of the Current production and delivery patterns



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Figures 7.1a and 7.1b Flowchart of ACI’s current production and delivery system

ACI operates a medium size alcohol distillery plant established on October 9, 1990 and is located

amidst vast sugarcane fields at Barangay Maruhatan, Lian, Batangas, a 2.5-hour drive from Manila.

ACI manufactures Ethyl Alcohol as its major product and liquefied Carbon Dioxide as fermentation by-

product. The distillery operates 8,400 hours a year. Current production rates require about 1,200 kW

of electricity from the grid. BATELEC I supplies the distillery’s electricity requirement at a rate of PhP7.20/kWh. Process steam requirement of the production plant is 18.2 tons/hour at 6.5 bars and is

currently supplied by three fire tube boilers running on approximately 70% Bunker Fuel Oil (BFO) and

30% biogas from the wastewater treatment facility at the plant. The steam is fed into the distillation

column wherein it interacts with the “beer” to produce ethanol and carbon dioxide. The excess steam

is discharged together with the slops into the wastewater treatment system of ACI. As such, there is

no condensate return considered in the total system.

Absolut Chemicals Inc.Processes

Electricity and Steam

CaneMolasses

RawSugar

EthylAlcohol

LiquidFertilizer

Sugar CaneFields

Sugar CaneCrops

Beverage(Alcoholic,

softdrinks)

CarbonDioxide

WasteWater

Treatment

Plant

Methane

BoilerA600 HP

Boiler B500 HP

Boiler C350 HP

ACI.Process

Requirements

Local ElectricCooperative

1.1 MW (Ave.)1.2 MW (Peak)Total 18.2

Tons/hr Steam6.5 bars

>30%Biogas FuelInput



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The boilers operate at 80% efficiency. ACI currently has no standby boiler. The ACI distillery plant

complex occupies a total lot area of around 9 hectares. The production facility occupies only around

12% of the complex while more than 60% is allotted to the company’s dedicated wastewater

treatment plant facility. ACI provides employment to 94 regular employees and 70 casuals. Fifty (50)

more employees have been hired under a private hauler in connection with the company’s Liquid

Fertilization Program.

7.3 Project baseline

The baseline scenario for the project is that APC continues to purchase grid electricity from Batelec,

use existing boiler equipment without any retrofit, which extends their capacity or lifetime, or improve

its fuel efficiency and acquire a new 800 BHP fire-tube boiler to provide the balance of 18.2 tons per

hour of process steam at 6.5 bars. The high investment cost is hindering the implementation of a

cogeneration plant at ACI. The 10-year old 350 BHP boiler will be retired and is given a scrap value of

PhP100,000.00.

The energy baseline is the energy (thermal and electrical) use of the existing equipment and facilityplus the new 800 BHP boiler. The electricity component of the energy baseline is adjusted for technical

and distribution losses of the Luzon grid and Meralco. The IPCC default emission factor for fuel oil,

77.4 t CO2e/TJ, is used to calculate emissions from the BFO used in the boilers to produce the process

heat.

Boiler A

600 HP

Boiler B

800 HP

ACI.Process

Requirements

Local ElectricCooperative

1.1 MW (Ave.)1.2 MW (Peak)Total 18.2

Tons/hr Steam6.5bar

Boiler C500 HP



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7.4 Project boundary and monitoring domain

7.4.1 Direct onsite and off-site Emissions

Direct on-site emissions are emissions from BFO combustion in the boiler equipment. Direct off-site

emissions are baseline emissions from electricity which used to be delivered from the grid but which is

going to be produced by the project.

7.4.2 Indirect onsite and off-site emissions

Indirect onsite and off-site emissions such as those from the production of the raw materials are

outside the project boundary and can be assumed to be equal for with and without the project.

7.4.3 Flow chart of the project

7.4.4 Project boundaries

The project boundary is the physical, geographical site of the cogeneration equipment.

7.5 Baseline methodology and calculation of the baseline emissions

7.5.1 Approved methodology

Using small-scale CDM project activity categories, cogeneration falls under category II.B Supply side

energy efficiency improvements – generation. Selected approach from paragraph 48 of the CDM

ACI.Process

Requirements

Local ElectricCooperativeMW (extra)

15.7Tons/hr Steam

1,000 psi(70 bars)

15 Tons/hr Steam 95 psi

1.2 MWTurbine

Boiler B600 HP

Boiler A500 HP

Boiler C900 HP

Reserve

3.2 Tons/hr Steam 95 psi



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modalities and procedures: “Emissions from a technology that represents an economically attractive

course of action, taking into account barriers to investment”.

7.5.2 Baseline: Assumptions and Analysis

This methodology is applicable to projects requiring both electricity and process steam

• Electricity is currently supplied from the grid

• Process steam is supplied by fossil fuel-fired boilers

• The facility would not have major efficiency improvements during the crediting period

7.5.3 Baseline Anthropogenic Emissions by Sources of GHG

The baseline emissions are the sum of emissions from fossil fuel combustion and the equivalent

emissions of grid electricity in the Philippines. The baseline emissions BEy (measured in tons of CO2

equivalents (t CO2e/yr) during a year (y) are expressed as

BE y = (Qf * IPCC f )+ (W y * W c ) (in tons CO2e/yr) and

Qf = Df * V f * HV f * H o where

Qf = quantity of fuel in the baseline scenario measured in energy units, Joule

IPCC f = are the CO2 equivalent emission factor per unit of energy of fuel, tons CO2e/TJ

H o = annual hours of operation, hours

HV f = average heating value of fuel, kJ/kg

Df = average density of fuel, kg/li

V f = required volumetric flow rate of fuel, li/hr

W y = annual grid electricity consumption, kWh

W c = emission coefficient for electricity consumption, kg CO2e/ kWh

BE y = (26,788 li/day * 350 days * 40,610 kJ/kg * 0.94 kg/li * 77.4 t CO2e/109 kJ)

+ (1.2 MW * 8400 hr*0.5981 kg CO2e/ kWh *10-3 t/kg)

= 33,730 tons CO2e per year

7.5.4 Leakage

The cogeneration equipment is new. Fugitive emissions from fuel production and CO2 emissions from

fuel transportation are considered unchanged with and without project activity.

7.6 Total Project GHG Emissions



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The cogeneration equipment will be purchased and installed complete with standard monitoring and

metering capabilities for fuel input, electricity generation and steam output. Grid electricity is

monitored, metered and billed by the utility.

8.3 Estimates of costs for monitoring and verification

The costs for monitoring and verification are included in the cogeneration equipment capital cost and

O&M cost. Skills training and improvement shall be conducted to enable manpower to operate,

maintain and monitor the cogeneration plant. The cost of technology transfer and capability building

is embedded in the equipment cost and operating and maintenance cost.

9. Financial Analysis

The analyses to be done in this chapter and in the next will be based on the principle of comparing

two alternative projects in solving an issue, which project could accrue more financial and economic

benefits and would justify the investments to be made.

Currently, ACI has three fire tube boilers, one with a rating of 600 BHP, another boiler with a rating

500 BHP and a third boiler with a rating of 350 BHP. The first two boilers are the main boilers used in

their daily operations, while the third serves as the stand-by boiler, in case either of the main boilers

would need to be shut down. This would mean that, if the reserve boiler would run in place of either

one of the main boilers that is inoperational, the operation would incur a reduction in capacity of

between 150 to 250 BHP. This is a rating down of 14% to 23%, which is already quite substantial.

This year, however, ACI has experienced more than seven percent (7%) increase in production fromlast year’s average and the three boilers are now running to produce the required steam. From the

2004 average steam requirement of 17 tons per hour, it has increased to 18.2 tons per hour. Clearly,

the reliability issue is becoming a bigger concern for the management and there is a need to address

the issue.

One alternative would be to procure a new 800-BHP fire tube boiler to serve as the main boiler

together with the 500-BHP boiler, producing the required 18.2 tons of steam per hour. The old 600-

BHP boiler would serve as a back-up boiler, in which case the rating down of steam production would

be less than 7%. The other alternative would be to use this opportunity to apply cogeneration. In the

cogeneration alternative, the company would procure a 900-BHP water tube boiler and turbine

generator, thereby producing both the steam requirements and generating the electricity

requirements of the plant. For brevity, the options are called Alternative A and Alternative B,

respectively. Their diagrams are shown in Figure 9.1.



15

The objective of the financial analysis is to examine the financial returns of investments needed to

implement all the phases of each alternative project. The evaluations are carried out by comparing the

costs and incremental revenues of each alternative project in terms of financial internal rate of return

(FIRR) and net present value (NPV).

Table 9.1 Historical Energy Consumption

2002 (Actual) 2003 (Actual) 2004 (Actual)

Annual Electricity Consumption (kWh) 2,723,000 5,159,891 6,330,345

Annual Electricity Bill (Peso) 13,509,832 29,139,377 33,917,759

Average Electricity Rate (Peso per kWh) 4.96 5.65 5.36

Average Electricity Requirement @ 8,400 hours

per annum (kW) 324.17 614.27 753.61

Annual BFO Consumption (Liters) 6,098,532 6,922,056 6,898,076

Annual BFO Bill (Peso) 61,051,794 73,714,359 80,080,350

Average BFO Rate (Peso per Liter) 10.01 10.65 11.61

Annual Diesel Consumption (Liters) 45,814 78,296 562,609

Annual Diesel Bill (Peso) 583,148 1,160,380 9,832,234*

Average Diesel Rate (Peso per Liter) 12.73 14.82 17.48

* Note: The 2002 and 2003 Diesel Fuel consumption figures are for the powerhouse only. The 2004

Diesel Fuel consumption covers the consumption of both Motor pool and the powerhouse.

Figure 9.1 Historical Energy Consumption

The historical energy consumption of ACI is shown in Table 9.1 and Figure 9.1. From the table it is

quite evident that the electricity requirement of the facility is growing, and a simple projection method

would show that the electricity requirement would reach an average of 1,000 kW by the year 2005.

During a coordination meeting with ACI on 26 August 2005, it was informed that their electricity

requirement is already at 1,200 kW. For this reason a turbine generator with 1.2 MW rating is

0

1000

2000

3000

4000

5000

6000

7000

8000

2002 2003 2004

Year

Annual Electricity

Consumption(MWh)

Averageelectricityrequirement(kW)

Annual BFOConsumption

(kiloLiters)



16

proposed. The electricity requirements in excess of what can be provided by the generator would be

procured from the local electric cooperative.

From the same coordination meeting, it was also informed that the electricity rates have already

increased to P7.20 per kWh and the BFO price has increased to P17.30 per liter. For simplicity of

computations, it is assumed that the prices shall be taken at constant 2005 prices. In the

computations, the rates of electricity and BFO given during the said meeting shall be used.

ACI is currently using dual-fired fire tube boilers. Methane gas from their digester and wastewater

treatment plant is mixed with BFO to generate steam. For a twenty-four hour operation, the two

boilers (with a total rating of 1,100 BHP) would theoretically consume 27,940 liters of BFO. From the

data given by ACI, their average daily BFO usage in 2004 only amounts to 19,709 liters only. This

translates into savings of 8,231 liters per day on BFO consumption or a hefty thirty-one percent

(31%) reduction on BFO consumption. From the interview with technical personnel of ACI they gave

the figure of 25% - 30% savings on BFO consumption. This validates their estimate.

Basically, the operations in each alternative will remain the same, operating days and operating hours

will remain as before. The energy requirement will be independent of the project. The major difference

would be the investments. In Alternative A, a new 800-BHP fire tube boiler would be procured. The

new boiler would be consuming 21,600 liters of BFO per day, or a total of 35,600 liters for both the

800-BHP and 500-BHP boilers. It is assumed that with the 7% increase in production, the digester

would also increase biogas production by 7%, or a total of 8,812 liters of equivalent BFO. For

Alternative A the actual BFO consumption would be 26,788 liters per day. No new technical personnel

would be employed, as ACI operations would practically remain the same.

In Alternative B, a new high-pressure 900 BHP water tube boiler that will generate high-pressure

steam to run a new turbine generator and to supply the steam requirements of their operations would

be procured. This new boiler would be consuming 27,936 liters of BFO per day. Alternative B would be

consuming a total of 41,936 liters of BFOe. Considering that the same amount of biogas would be

available for Alternative B, the actual BFO consumption would be 33,124 liters per day. In terms of

manpower, Alternative B would employ additional technical personnel to augment their present

personnel complement. In both alternatives, the old 350-BHP boiler would be sold as scrap for a price

of P100,000.00. Table 9.2 shows the basic assumptions made for each alternative project.

In Alternative A, all electricity requirements would be procured from the local electric cooperative

(BATELEC I). Alternative B would be producing 1,200 kW for ACI’s electricity requirements. Any

excess requirement would have to be procured from BATELEC I. In effect Alternative B would mean

savings on electric bills in the amount of 1,200 kW x number of operating hours (taken at 8,400 hours

per year) x the average cost of electricity (P7.20 in August 2005). The benefits, if any, of not burning



18

Mechanics 0.23

Electricians 0.68

Annual O & M Cost, Million Pesos 0.40 2.40

Total, Annual Costs 235.18 202.97

Payback (months) 14.34

Greenhouse Gas Abatement Calculation

For the year 2004---86,649 Gg CO2 at 60,488 GWhr

Emission Coefficient, kg of CO2 per kWhr 0.5981 0.5981

CO2 Trading, US$ per ton 5.00

Foreign Exchange Rate, Pesos per US$ 56.00 56.00

Annual Carbon Credit, Million Pesos 2.21

Payback (months) 13.42

Economic Evaluation7 Alternative A Alternative B

Shadow Pricing, Forex 1.20 1.20

Shadow Pricing, Labor 0.80 0.80

Electricity GenerationOne BFOE would generate electricity of kWh 600 600

BFOE to generate required electricity 16,800.00 -

Oil Price per barrel, US$ 80.00 80.00

Economic Cost of BFOE, Million Pesos 90.32 -

Operating and Maintenance Costs

Chemicals and Spare Parts, Million Pesos 0.48 1.80

Manpower, Million Pesos

Mechanic - 0.18

Electricians - 0.54

Annual O & M Cost, Million Pesos 0.48 2.52

Investment Costs, Million Pesos 29.23 71.82

New Boiler (Fire tube w/o and Water Tube w/) 28.80 36.00

Steam Turbine - 24.00

Powerhouse - 7.52

Installation and Commissioning 0.43 4.30

9.1 Overall Costs Estimates For Alternative A, only one piece of equipment would be procured, a new 800-BHP fire tube boiler. No

new building would be required, as it would be housed in the same area where the 350-BHP boiler

sits. There would also be installation and commissioning costs.

7NEDA (2000).



19

For Alternative B, two major pieces of equipment are to be procured for this project. These are: a

high-pressure water tube boiler and a steam turbine generator. A new powerhouse would also have to

be built to house the new equipment. There will also be attendant cost in installing and commissioning

the equipment. Table 9.2 also shows the estimated costs of the major project components of each

alternative project.

There will be additional personnel that must be hired to operate and maintain the new system of

Alternative B. Considering that there is already a well-staffed Electrical Department in the company;

three (3) electricians (one electrician per shift) and an additional mechanic would be employed to take

care of the additional workload. The all-in salary of the electricians and mechanic is taken as

P15,000.00 per month each. It is further assumed that all the other benefits, such as sick leave and

vacation leave, SSS contributions, 13th month pay, etc., would be 25% of their basic salary.

The new system of Alternative B would also require more expensive chemicals and spare parts

considering that the requirements of the system would be more stringent than the existing boiler

system. For this reason, Chemicals and Spare Parts would require some P 1,500,000.00 per annum for

Alternative B and only P400,000.00 per annum for Alternative A. All prices and figures are based on

constant CY 2005 prices.

9.2 Project Financial Analysis

Analytical Method and Conditions

Two discounted cash flow techniques were employed to analyze and evaluate the feasibility of the

alternatives in terms of the financing, the Financial Internal Rate of Return (FIRR) and Net PresentValue (NPV).

Definition of FIRR: The Financial Internal Rate of Return (FIRR) is calculated from the cash flow in

the implementation and operation of the project, and obtained by equating the present value of

investment costs (In, as cash out-flows) and the present value of net incomes (Bn, as cash in-flows).

This can be shown by the following equation.

M M In Bn

∑ ∑

n = 0

(1 + r)n

=

n = 1

(1 + r)n

Definition of NPV: The Net Present Value is a method of evaluating projects by finding the present

value of the future net cash flows discounted at the Weighted Average Cost of Capital (WACC) and the



20

initial investment amount. If the NPV is positive, the project should be accepted, while if the NPV is

negative, it should be rejected.

The primary consideration in the computation of NPV is the determination of Weighted Average Cost of

Capital (WACC). The WACC is the weighted average of the costs of the different sources of funding for

the project, either from equity or debt. The cost of debt (kd) is the after-tax interest rate while the

cost of equity (ke) is the required return by the company for the project. The project could be

assumed to be funded 85% by debt and 15% from equity. The average interest rate of bank for loans

is taken at 12%. We could also assume that the required rate of return by Absolut Company is 20% to

account for the foreign exchange risks and other risks. Therefore, the discount factor to be used is:

WACC = w1kd + w2ke

WACC = (85%)(12%) + (15%)(20%)

WACC = 13.20%

9.2.1 FIRR and NPV without CO2 credits

In the FIRR calculation, the incremental revenue or benefit of each alternative project is taken as the

recovery of production losses during downtime of one of the main boilers (for both alternative

projects) and difference in the total cost of the existing system and the total cost of the proposed

boiler-generator system (for Alternative B). The total cost of both alternative projects is the sum of

the cost of operating and maintaining the present boiler system, which includes the cost of the BFO

consumed; the personnel expense; the cost of chemicals and spare parts, and the electricity costprocured from the electric cooperative (in the case of Alternative A) or the cost of operating the new

boiler-generator system, including cost of the BFO consumed; the personnel expense; and the cost of

chemicals and spare parts thereof (in the case of Alternative B). Considering that the recovery of

production losses from down time of either boiler is common on both alternative projects, there would

no longer be a need to do an approximation of these losses.

For Alternative A, the actual BFO consumption would be 26,788 liters per day. The total BFO

consumption for Alternative B would be 33,154 liters per day. Alternative B would, however, have the

benefit of buying less electricity (1,200 kW) from BATELEC I.

To maintain the efficient operation of the new boiler of Alternative A or the new boiler-generator

system of Alternative B, a more stringent maintenance system would have to be put in place. It is

assumed that two percent (2%) of the total cost of investments would be allocated every year for the

proper upkeep and maintenance of the new equipment in addition to the present allocation for

equipment maintenance. It is also assumed that on the fifth and tenth year major investments would



21

have to be made at a cost of about twenty percent (20%) of the initial investments. The main issue

would be: “Would the savings in electricity bills be enough to recoup the additional investments made

in the boiler-generator system?” Table 9.3 shows in tabulated form the analysis on the financial

viability of Alternative B.

Table 9.3 below shows that the project has an FIRR of 80.65%. In the NPV calculation, using 13.2%

discount factor, the project posted a positive NPV of PHP 110.44 million. The payback period is only

fifteen (15) months. From the foregoing results, the project is worthwhile undertaking.

Table 9.3 Financial Evaluation

Alternative A Alternative B Net Benefit

Year

InvestmentCosts

Electricity

Cost BFO CostO & MCosts

TotalCosts

InvestmentCosts

ElectricityCost BFO Cost

O & MCosts

TotalCosts

Year 0 24.40 24.40 62.90 62.90 -38.50

Year 1 0.49 72.58 162.20 0.4 235.67 1.26 0.00 200.57 2.4 204.22 31.44

Year 2 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 3 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 4 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 5 4.88 72.58 162.20 0.40 240.06 12.58 0.00 200.57 2.40 215.55 24.51

Year 6 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 7 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 8 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 9 0.49 72.58 162.20 0.40 235.67 1.26 0.00 200.57 2.40 204.22 31.44

Year 10 4.88 72.58 162.20 0.40 240.06 12.58 0.00 200.57 2.40 215.55 24.51

NPV @13.20% 110.44

FIRR = 80.65%

9.2.2 The incremental cost of carbon abatement

Considering that the project could be eligible for carbon credits under the Clean Development

Mechanism (CDM), an evaluation was also made to evaluate its FIRR and NPV with the carbon credits

factored in. Any carbon abatement of the Alternative B can be calculated from the difference between

the total project emissions and the total baseline emissions. Project emissions are from BFO

combustion while the baseline emissions are from grid electricity emissions and BFO combustion.

Following the Baseline Methodology, the baseline emission factor for the Luzon grid is the average of

the weighted emission factors of the Operating Margin [OM] and the Build Margin [BM] and would

seem to represent best the status of the grid in the Business As Usual scenario. The Operating Margin

is the grid mix of all generating sources serving the system while the Build Margin is the grid mix of

recent capacity additions (newly installed plants) defined as lower of most recent 20% of plants built

or the 5 most recently built plants. The baseline scenario would be the amount and type of electricity

that would be generated by the operation of grid-connected power plants and by the addition of new

generation sources. Taking the results of the calculations made in the Project Design Document



22

(PDD) of the 20 MW Nasulo Geothermal Project, the emission factor for the Luzon-Visayas grid is

0.5981 kilogram of CO2 per kWh of electricity produced. (Source: http://www.dnv.com/certification/

climatechange/Upload/PDD%20and%20MP%20Nasulo%20Oct%203.pdf ). The carbon credit of the

project from this component would come to 6,029 tons CO2 equivalent per year.

The BFO-fed boilers would also produce CO2 during their operation. The amount of CO2 produced is

calculated from the following:

• The BFO has a Low Heating Value of 9,700 kcal/kg or 40,610 kJ/kg.

• The BFO has a density of 0.94 kg/liter

• The BFO produces 77.4 tons of CO2 /1x109kJ

• The amount of CO2 produced per liter of BFO is 0.94 x 40,610 x 77.4 divided by 1 x 109 or

0.002954 tons per liter

The new boiler-generator system would burn more BFO and therefore emit more CO2 into the

atmosphere. Using the foregoing coefficient, the incremental CO2 production between the 800 BHP

and 900 BHP boilers would be 6,552 tons per year.

Comparing the two alternative projects, Alternative B would have a total carbon abatement of -523.32

tons per year. There is therefore an increase in emissions from the baseline and the project will not

be eligible for carbon credits.

9.3 The Financing Plan

The financing plan envisioned for the project is in-house financing. The project will be financed from

internally generated equity and through borrowing. There will be no CDM component for the project

as it incurs an increase in emissions from the baseline. This study evaluates the financial and

economic viability of the project if financed through a loan facility from the Development Bank of the

Philippines (DBP). The company shall provide 15% of the investment cost as equity while 85% will be

borrowed from DBP at a rate of 12%. The return on the company’s equity is at 20%. The weighted

average cost of capital is therefore 13.20%.

9.4 Financing Mechanisms to Promote Cogeneration

There are several financing options available for the project.

1. In-house Financing – refers to financing an investment from internally generated equity

and/or through borrowing by the company with the intention of acquiring, operating and

maintaining the cogeneration technology. The advantages of this option are the company’s



23

control over the implementation and total savings flow. The disadvantages include

obsolescence and the large capital commitment.

2. Build-Operate-Transfer Scheme – refers to a financing option wherein the company engages a

supplier or Energy Service Company or ESCO in the construction, financing and operation of

the technology over a certain period of time [cogeneration period]. During the cogeneration

period, the company commits to purchase the output of the technology at an agreed rate that

gives the supplier its required rate of return. At the end of the period, the supplier transfers

the technology to the company.

3. Performance Contracting– refers to a financing option wherein the company focuses on the

delivery of the cogeneration output rather on the ownership of the technology itself. The

equipment is installed, maintained and owned by the equipment supplier or ESCO. The

company agrees to purchase heat and/or electricity at a discounted rate for a fixed contract

period, usually five to seven years, thereby incurring less risk but also receiving a smaller

proportion of the benefits. Under performance contracting, the company retains the option to

cancel the agreement as long as the ESCO is given reasonable notice and the company pays a

penalty. Additionally, the company may purchase the unit after the expiration of the lease.



Existing 600-BHP Boiler (to

serve asstandby)

Existing 500-BHP Boiler

(to serve asmain boiler)

New 800-BHP Boiler

(to serve asmain boiler)

Alternative A

Existing 600-BHP Boiler (to

serve asstandby)

Existing500-BHPBoiler (toserve as

main boiler)

Alternative B

Electricityfrom newsteamturbinegenerator

15 t/hr95 psi

3.2 t/hr95 psi583 li/hr

18.2 t/hr95 psi

6.5 bars

5.2 t/hr95 psi700 li/hr

13 t/hr95 psi900 li/nr

18.2 t/95 psi



26

operations. A portion of the profit may then be shared with the workers, thereby increasing their

salaries and wages, and therewith their disposable income.

10.2 Social and gender

Social and Gender equity: There would be no specific impact on gender equity, however, job creation

could bring employment for women and poverty alleviation elements could be designed to specifically

target women.

10.3 Economic Analyses

Analytical Method

The same method is employed to calculate economic internal rate of return (EIRR) and economic net

present value (NPV), using the benefit of the project to the society in place of the revenue. Except forthe revenue, the financial data used and factors assumed for the financial analysis are converted to be

utilized in the economic analysis.

The analyses would use the Opportunity Cost of Capital (OCC) in lieu of the WACC as the discount

factor. In the Philippines, the National Economic and Development Authority (NEDA) uses an OCC of

15%, which would also be used in the calculations herein. The economic analyses would also use

shadow pricing for goods and services with foreign exchange components and for local labor. The

shadow pricing factors to be used are 1.2 and 0.8 for foreign exchange components and labor,

respectively.

It is assumed that the boiler and steam turbine would be imported, so the shadow price factor of 1.2

would be used. It is further assumed that 30% of the building cost would be labor; therefore, the price

for the powerhouse will have a shadow price factor of 0.94. The Installation and Commissioning

component, on the other hand assumes that there would be 70% labor component, ergo, a shadow

price factor of 0.86.

10.3.1 The EIRR and NPV without CO2 credits

The major benefit to the society of the project would be on the lesser demand for imported fuel oil and

imported coal to generate power on the grid. Based on the Philippine Energy Plan data, one barrel of

fuel oil equivalent (BFOE) could generate 600 kilowatt-hour of electricity. The existing system requires

an average of 1.2 MW, and the company operates 24 hours a day, seven days a week, with planned

downtime of about fifteen days a year for maintenance. This means that this plant alone consumes

16,800 barrels of BFOe to generate the required power.



27

When the plant converts to the boiler-generator system, it will generate 1.2 MW of power for its own

use, and getting whatever excess power requirements from the local electric cooperative. The

difference would be the savings for the society. The price of US$67.00 per barrel of oil and the

shadow price factor of 1.20 were used in the calculation.

Using the said assumptions, the project posted an EIRR of 79.70% and an NPV of P 120.28 Million at

the discount rate of 13.20%. Table 10.1 shows the calculations for the EIRR and NPV of the project

without the carbon credits.

Table 10.1 Economic Evaluation without CO2 Credits

Alternative A Alternative BNetBenefit

Year

InvestmentCosts

BFOECost BFO Cost

O & MCosts

TotalCosts

InvestmentCosts

BFOECost BFO Cost

O & MCosts

TotalCosts

Year 0 29.23 29.23 71.82 71.82 -42.59

Year 1 0.58 75.64 162.20 0.48 238.91 1.4364 0.00 200.57 2.52 204.52 34.38

Year 2 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 3 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 4 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 5 5.85 75.64 162.20 0.48 244.17 14.36 0.00 200.57 2.52 217.45 26.72

Year 6 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 7 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 8 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 9 0.58 75.64 162.20 0.48 238.91 1.44 0.00 200.57 2.52 204.52 34.38

Year 10 5.85 75.64 162.20 0.48 244.17 14.36 0.00 200.57 2.52 217.45 26.72

NPV @ 15.00% 108.06

EIRR = 79.70%

10.4 Sensitivity Analysis

Sensitivity Analyses were undertaken to see how the viability of the project would react to changes in

the assumptions made. Different scenarios were looked at, namely:

(a) The investment costs would increase by 20%;

(b) The electricity cost of would increase or decrease by 20%;

(c) The price of BFO would increase or decrease by 20 and 50%%;

(d) The price of O&M would increase by 20%;(e) All of the foregoing negative impact scenarios happening altogether (but up to 20%

variance only).

The following table shows the effect of the aforementioned scenarios to the financial viability and

economic feasibility of the project.



28

Table 10.3 Sensitivity Analyses

Scenario

A

Scenario B

(increase

20%)

Scenario B

(decrease

20%)

Scenario C

(increase

20%)

Scenario C

(increase

50%)

FIRR without Carbon Credits 66.29% 118.89% 40.99% 60.05% 27.01%

Financial NPV without

Carbon Credits (P Million)101.89 179.47 41.42 73.75 19.22

EIRR without Carbon Credits 65.48% 115.74% 42.36% 61.08% 31.60%

Economic NPV without

Carbon Credits (P Million)110.83 192.22 42.04 83.80 24.35

Table 10.3 Sensitivity Analyses (Continued)

Scenario

C

(decrease

20%)

Scenario

C

(decrease

50%)

Scenario

D

Scenario

E

FIRR without Carbon Credits 100.93% 131.10% 79.59% 9.38%

Financial NPV without

Carbon Credits (P Million)146.93 201.66 108.54 -5.52

EIRR without Carbon Credits 98.04% 125.34% 78.71% 13.48%

Economic NPV without

Carbon Credits (P Million)141.55 191.77 118.34 -2.37

The increase in the price of BFO has the greatest effect on the viability of the project. An increase of

20% in the price of BFO meant a decrease of about 20.6% on the FIRR and about 18.6% on the EIRR.

Next, would be an increase in the investment costs. An increase of 20% in the investment costs meant

a decrease of about 14.4% on the FIRR and about 14.2% on the EIRR. An increase of 20% on the cost

of electricity, however, translates into an increase of about 38% in the FIRR and 36% in the EIRR. In

the final analysis, this is just a comparison on how the financial and economic figures would be

affected by the changes in the prices of electricity and BFO. In all of the individual scenarios, the

project posted figures that show that it is still viable and feasible. However, if all the negative impact

scenarios would occur altogether (but at +/-20% only), the project alone, without the carbon credit,

would fail the investment criteria. It must be emphasized that the possibility of the electricity pricesgoing down while the price BFO is going up is very unlikely, considering that fossil fuel also contributes

to the electricity generation of the grid. Alternative B would still be the better option even if the BFO

price increases by 15% more than the electricity price.

Considering the rapid increases in the prices of crude oil in recent months, the sensitivity of the

project’s FIRR to even higher oil price increases is also analyzed. With BFO price of P30/liter, the



29

project will not be viable, the evaluation figures would be negative, i.e., and the decision would be not

to implement the project. Of course, that is on the assumption that the price of electricity would

remain as is and won't move in the same direction as the price of oil.

The changeover price would be at P27.77/liter. At that price the FIRR would just equal the WACC. Of

course, the WACC was based on the assumption that the bank would finance 85% of the investment

cost at only 12% p.a. If the bank would finance only 60% of the investment and at 14%, and equity

would be at 30%, the WACC would be 20.40%. The changeover price would then be P26.86/liter.

The impact of oil price increases can be slightly offset in the event that electricity prices will fall with

the advent of WESM. However, based on experience from other countries undergoing trade

liberalization and deregulation, electricity prices are not likely to fall with competition. Nevertheless,

the increase would be slight such that the prices will be lower than what they would be without the

reform.

11. Stakeholders’ Comments

The ACI Plant Manager and technical staff have known about cogeneration technology and have

initially planned to propose to their owners to the installation of a cogeneration plant at their facility.

Their limited knowledge of the technology and the perceived reluctance of the owners to invest in a

plant have hindered the progress of the concept. The engineers, particularly, the boiler supervisors

and technicians, are aware of the risks involved in operating old boilers and the reduced reliability of

production without a standby boiler. These urgent concerns have been slowly aired to management.

They are hopeful that the results of the PREGA pre-FS will sway management’s decision of projectimplementation.

Furthermore, the wastewater treatment plant and the corresponding benefit of biogas production in

ACI’s facility have been recognized and the Plant Manager is eager to expand their biogas production if

and when the demand of their ethanol product increases.

12. Key factors impacting project & baseline emissions

Since the project boundary covers only the cogeneration equipment, the key factors that impact the

project and baseline emissions are the quantity and quality (density and heating value) of the fossil

fuel used and the country’s power generation mix, particularly the operating and build margins which

are the bases for calculating the weighted emission factor for the grid. These factors affect the

emission coefficients. If the country shifts to a mix that is dominated by renewable energy, the grid

electricity may have lower emissions than the fossil-fuel-fired cogeneration plant. This project was

conceptualized at a time when grid electricity and corresponding emissions were thought to be

dominated by oil and coal. With the operating margin and build margin largely dominated by



30

renewable energy and natural gas, this oil-based cogeneration project was found to have greater

emissions than the baseline. In this case, a cogeneration plant powered by renewable energy should

be considered.

12.1 Project Uncertainties and Risks

The project faces several types of uncertainties and risks: conventional projects risks and, if CDM

financing is considered, CDM-related policy risks and market risks.

Conventional project risks may be broadly classified into i) construction risks (referring to time and

cost overrun), and ii) operational risks (involving technology performance, fuel, or product supply,

market operation, interest rates, political, legal, environmental, and financial factors. Though these

risks are generic to projects, these relate to project performance, which affect its ability to deliver the

expected quantity of CERs. Delays in time and cost overruns are not uncommon in project

implementation. However, this pre-feasibility study has shown that the payback time is very shortand the investment cost is not very steep, that these risks can be readily absorbed by the project.

The huge FIRR attests to the viability of the project even under uncertainty. Operational risks are

minimized in that the technology is proven. A major uncertainty, however, is the foreign exchange

rate and the corresponding foreign exchange cost of fuel.

The nature of competitive environments would mean that electricity prices would be highly volatile

with the implementation of the wholesale electricity spot market (WESM) in the country, scheduled in

2006. In the case of the US power industry restructuring, the US DOE found that because of the high

level of uncertainty surrounding the future structure of their electric power industry, it is not possible

to determine the precise conditions that will set electricity prices in the future8. While electricity prices

could go theoretically down, experience in competitive markets have shown that electricity prices

continued to increase albeit at a lower rate than what they would be in the absence of competition.

ACI will reduce their exposure to this uncertainty by generating their own electricity.

The ratification of the Kyoto Protocol significantly reduced CDM-related policy risks. If CDM financing is

considered, other CDM-related policy risks the proponents will have to face include the risk that the

host country will not comply with its obligations; and risk that the specific baselines and procedures

used in the project will not be approved. There is a CDM-related market risk because CER pricing is

highly speculative and that the development of the CER market and the evolution of the CER prices

are highly unpredictable. However, the financial and economic analyses of this project has shown that

the carbon credits do not have a major influence on the financial internal rate of return, net present

value and economic internal rate of return of the project. CDM-related risks are therefore also

minimized because the project viability is not sensitive to uncertainties in carbon credits.

8US DOE (2000)



31

Furthermore, the risk of CO2 CER price volatility is only a risk up to the point at which the CER’s are

sold, then the buyer takes the risks and rewards of future CER price volatility for the 10-year or

multiple 7-year crediting periods (with readjustment between periods).

The long CDM qualification process also poses a risk especially since there is an underlying uncertainty

if CDM will still be available after 2012.

13. Conclusions and Recommendations

Cogeneration is an appropriate EE technology in a food industry like ACI. Cogeneration gives benefits

to the company in the long run ensuring healthier profits and healthier environments.

This pre-feasibility study has shown that for the ten-year crediting period, the FIRR, Financial NPV and

EIRR without carbon credits are 80.65%, PhP110.4 Million, and 114.67%, respectively. The payback

time for the project is around fourteen (14) months. With interest rates at 12% and the cost of equityat 20%, the FIRR achieved is way above the weighted average cost of capital of 13.20%.

Given its financial viability and economic benefits, the project is worth considering. More benefits will

likely be realized if the cogeneration plant will be run on renewable energy. A thorough study on this

option is therefore recommended if Absolut is inclined to pursue the project. This pre-feasibility study

has shown that as an energy efficient supply side option, cogeneration promises a potential for energy

savings wherein self-generated electricity is cheaper than grid-supplied power. If the cogeneration is

RE-based, environmental benefits and carbon credits will also be realized.



14. References

1. DOE (2000), Electricity Prices in a Competitive Environment: Marginal Cost Pricing of

Generation Services and Financial Status of Electric Utilities, EIA, US Department of Energy

http://www.eia.doe.gov/electricity/elec97.pdf

2. DOE (2002). Philippine Energy Plan 2002-2011, Department of Energy.

3. DOE (2004) Philippine Energy Plan 2004-2013, Department of Energy.

4. DOE (2005) Philippine Energy Plan Update 2005-2014, Department of Energy.

5. Goco, J.A., (2003) CDM in the Philippines: Opportunities and Initiatives, Southeast Asia Forum

on GHG Mitigation, Market Mechanisms and Sustainable Development, 10-12 September

2003, EDSA Shangri-La Hotel, Philippines

6. http://cdm.unfccc.int/EB/Meetings/016/eb16repan1.pdf

7. http://cdm.unfccc.int/methodologies/approved

8. http://www.adb.org;

9. http://www.adb.org/Documents/Policies/Energy_Initiatives/energy_ini322.asp? p=policies

10. http://www.ajinomoto.com.ph/indexmain.php

11. http://www.dnv.com/certification/climatechange/Upload/PDD%20and%20MP%20Nasulo%20O

ct%203.pdf

12. http://www.doe.gov.ph

13. http://www.ipcc-nggip.iges.or.jp/public/gl/

14. Lee, Myung-Koon, ed. (2004), The UNEP Project CD4CDM Information and Guidebook, 2 nd ed.

Denmark, June 2004

15. NEDA (2000), Advanced Manual on Project Evaluation, Project Development and Evaluation

Manual, Volume 2, National Economic and Development Authority.

16. UN ESCAP (2000), Guidebook on Cogeneration as a Means of Pollution Control and Energy

Efficiency in Asia, United Nations, New York.

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