baseline study for the ghg component of the gemina rice husk web view · 2015-06-19for...

Prototype Carbon Fund Gemina Rice Husk Baseline Study 06/05/2023

THE PROTOTYPE CARBON FUND

Baseline Studyfor the Greenhouse Gas Component of the

Gemina Rice Husk Project

Revision 23rd May, 2002

Prepared by Bronzeoak Corporation under the Prototype Carbon Fund’s supervision

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List of Contents

(1) Background and Purpose of the Baseline Study 8(1.1) Background for Baseline Study 8(1.2) Purpose of Baseline Study 8(1.3) Baseline Selection Concepts 8

(2) Existing Rules for Baselines 10(3) Principle Methodologies for Baseline Selection 11

(3.1) Baseline Methods 11(3.1.1) Standard-Oriented methods 11(3.1.2) Project-Specific methods 11

(3.2) Selection of Baseline Methodology 12(3.3) Common Baseline Issues 13

(4) Description of Gemina Rice Husk Project 14(4.1) Project Location and Country Background 14(4.2) Gemina Rice and Flour Mill 14

(4.2.1) Basic Operational Characteristics 14(4.2.2) Electrical Consumption and Cost 15

(4.3) Proposed Power Plant 15(4.4) Environmental Impacts of the GG 17

(5) Nicaraguan Issues Related to the Baseline 18(5.1) General Issues 18

(5.1.1) UNFCCC and Kyoto Protocol requirements 18(5.1.2) National legislation 18(5.1.3) Energy Sector and Climate Change 18

(5.2) Issues Applicable to the Electrical Generation Baseline 19(5.2.1) Legal Constraints 19(5.2.2) Technical constraints 19(5.2.3) Political constraints 19

(5.3) Issues Applicable to the Dumped Husk Baseline 20(5.3.1) Legal constraints 20(5.3.2) Technical constraints 20(5.3.3) Political constraints 21

(6) Selection of Baseline Approach and Additionality of GG 22(6.1) Small Scale project 22(6.2) Barriers to investment 23

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(6.3) Evidence of the binding nature of these barriers 25(6.4) PCF assistance to overcome the barriers 25

(7) Establishing the Baseline for Electric Power Replacement 26(7.1) Interconnected Electrical System and GG Interaction with other Generators 26(7.2) Electrical Supply and Demand 27

(7.2.1) Past Generation & Consumption 27(7.2.2) Future Electricity Production and Consumption- 30(7.2.3) Comparative Marginal Cost of Generation 31(7.2.4) Will GG be likely to operate without restriction once built? 33(7.2.5) Plant Costs, Dispatch Order and Emission Rates in 2000 35

(7.3) Time Dimension of Selected Baseline Scenario 35(7.4) Electrical System Expansion Scenarios – Period 2003-2012 36

(7.4.1) Plausible Scenario 36(7.4.2) Implausible Scenarios 39(7.4.3) Electrical System Expansion Option 2013-2023 39

(7.5) Implausible Scenarios 2013-2023 39(7.6) Use of Proxy Plant Approach 40

(8) Establishing the Baseline for Reduced Dumping of Husk 41(8.1) Husk Disposal Baseline 41(8.2) Past Husk Disposal Practices 41(8.3) Disposal Scenario for Husk Dumping Baseline 42

(8.3.1) Husk Quantity 42(8.3.2) Transport Related Emissions 43

(9) Establishing the baseline for substitution of rice husk ash for cement 44(10) Indirect Emission Effects (Leakage) 46(11) Calculation of Certified Emission Reductions 47(12) Estimated CERs Over Project Lifetime 48

(12.1) CER’s from Avoided Electrical Generation (Low operating mode) 48(12.1.1) Emissions of CO2 from electricity generation 48

(12.2) CER’s from Avoided Electrical Generation (Optimal operating mode)49

(12.3) CERS from Avoided Husk Disposal (Low operating mode) 49(12.3.1) CER’s from avoided transport of husks 49(12.3.2) CER’s from avoided dumping of husks 50(12.3.3) CER’s from avoided open husk burning 52

(12.4) CER’s from Avoided Husk Disposal (Optimal operating mode) 54(12.4.1) CER’s from avoided transport of husks 54(12.4.2) CERs from avoided dumping of husks 54(12.4.3) CER’s from avoided open husk burning 54

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(12.5) CERS from substituted cement with RHA – Optimal operating mode only 55

(13) Estimated CER summary for project lifetime 57(14) Risks potentially affecting CERs and mitigation measures 58(15) Additional sources of reference 60

Annex 1 Nicaragua Background 61(A1.1) General information 61(A1.2) Political background 62(A1.3) Economic background 62(A1.4) Social background 62

Annex 2 Background to the Electrical Sector in Nicaragua 64(A2.1) Interconnected Grid 64(A2.2) Past and Current Generation & Consumption 64(A2.3) Organization & Institutional Framework 66(A2.4) Transmission & Distribution 67(A2.5) Electricity Market 68(A2.6) Ownership of Power Plant 68(A2.7) Deregulation process 69(A2.8) Energy Policy and Strategy 69

Annex 3 Carbon Dioxide Emissions from Nicaraguan Power Plants 71

Acknowledgement:

This document was prepared with input and assistance from Bronzeoak Limited and Prolena, a Nicaraguan NGO. Information was also provided by Gemina-INA, the host of the proposed project, and other sources in Nicaragua.

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Executive Summary

When operational in 2003, the Gemina Generador power plant (GG) will burn 2.75 tonne of waste rice husks per hour to generate up to 1,575 kW of electricity. Over the course of a year, depending on whether the plant only supplies on-site loads or supplies at full capacity on a near continuous basis, the husk consumption is predicted to fall in the range 15,000 tonne to 21,700 tonne.

The GG will be located at the Gemina rice and flour mill complex in Chinandega, Nicaragua. Currently the Gemina rice mill produces 18,000 tonne/year of husk. By 2003, following an expansion, the Gemina rice mill is predicted to produce 25,000 tonnes of rice husk waste.

The GG will result in a net reduction of green house gas (GHG) emissions to the atmosphere from two components:

First, the electricity produced will be used to substitute for electricity that would otherwise be produced using fossil fuels. This will result in a reduction of carbon dioxide emissions.

Second, the GG will largely eliminate the current practice of dumping of waste husks from the Gemina rice mill in open piles. This will reduce: the emission of carbon dioxide, from trucks that haul the waste, methane, from decomposing husk, and both methane and nitrous oxide emissions from the periodic burning of the piles to reduce volume.

The purpose of a Baseline Study is to consider possible approaches and then develop and justify reference scenarios (Baselines) for each GHG component of a proposed project. This document describes the development of baselines for the GG and provides information to justify their use. The intention is that future reductions of GHG emissions attributable to the GG can be derived in a transparent manner using the baselines and associated calculation procedures.

Since the methodology for Baseline Studies is relatively new and has not yet been formalized within the UNFCCC/Kyoto Protocol context, a broad range of possible baseline methodologies are first examined. Through a screening process the possible methodologies applicable to the GG case are then identified. Finally, those that were selected are explained, justified and used to define the baselines for GG.

In keeping with the requirements of the Kyoto Protocol for CDM projects, the Study examines the issue of project “additionality”. At the same time, taking into account the relatively small size of the GG, the Study seeks to produce a justifiable approach without unnecessary complexity and undue cost burden to the project.

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The selected component baselines and their summary definitions are:

Electrical Generation Baseline

Divide the design life of the GG (2003 to 2023) into two periods – first period (2003 to 2012) and second period (2013 to 2023),

The electricity from GG reduces electricity that would otherwise be produced by a ‘proxy’ power plant fuelled by residual fuel oil,

GHG emission rates for the ‘proxy’ power plant will be applied to the quantity of electricity generated by GG to measure its GHG emission reductions,

For the first period fix the proxy emission rate at the ‘Nicaragua Unit 1 Power Plant rate (this power plant, and the similar Managua Power Plant, both burn Heavy Fuel Oil (HFO) and act as the supply/demand balancing plants on the Nicaraguan inter-connected grid),

Allow changes to the emission value of the ‘proxy’ plant emission rates at end of 2012 such that a revised ‘proxy’ plant can be used for the second period.

Husk Dumping Baseline

Assume husk produced, minus an allowance for possible sales, would be dumped if the GG wasn’t operating,

Assume that at six monthly intervals the dumped husk is burned,

Use GHG assessment guides to estimate the methane from decomposition and open burning, and the nitrous oxide from burning,

Use site data for diesel consumption and generic data for the emission rate, to estimate the transportation emission of carbon dioxide avoided by elimination of husk dumping

The baseline scenario builds on the assumption that the status quo ante continues to prevail. The approach selected to assess baseline emissions corresponds with paragraph 48 (a) of the Marrakesh Accords which states that project developers may choose historic or actual emissions to determine baseline emissions. Appropriateness of this choice is demonstrated by an analysis of barriers that are preventing the implementation of the project. Barriers are acknowledged to especially impact the realization of small-scale projects such as the Gemina power plant.

Although not strictly part of the task of producing the Baseline Study, this report also contains predictions of GHG reductions using the selected baselines. These are based on two possible scenarios: The low operation mode in which electricity is only sold to on-site consumers and the optimal operation mode which includes sales to off-site consumers (see Section 12.)

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For the period, 2003 through 2012, the predicted annual reduction for the low operation mode is 10,971 tonnes CO2 and for the optimal operation mode, it is 17,409 tonnes CO2. These values are the sum of all GHG reductions adjusted to equivalent tonnes of carbon dioxide.

The GHG reductions estimated for the second period are subject to a larger margin of variation than during the first period. This is because of the possible revision of the proxy plant emission rate for electrical substitution during the second period.

Estimated annual emission reductions during the second period (2013-2023) sum to 9,335 tonnes CO2 for the low operation mode and 14,952 tonnes CO2 for the optimal operation mode.

Documents consulted and information used to develop the Baselines included: reports published by MARENA, INE, CNE; information from CNDC and INE; guidelines published by World Bank (WB) and the Prototype Carbon Fund (PCF)

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(1) Background and Purpose of the Baseline Study

(1.1) Background for Baseline Study

The Gemina Rice Husk project will convert waste husk from rice milling into electricity for use as a substitute for fossil fuel generated electricity. By using the waste husk in this manner, a substantial reduction in open site disposal of waste rice husks will result. The project is being developed by Bronzeoak Group and Gemina Group as co-developers. The Groups have agreed to form a single purpose Nicaraguan company to be called Gemina Generador S.A. (GG) that will become the legal entity for implementation and operation of the project.

The project is intended to operate as a Clean Development Mechanism (CDM) project under Article 12 of the Kyoto Protocol, to the United Nations Framework on Climate Change (UNFCCC) and as such will have to comply with all relevant UNFCCC and host country (Nicaragua) regulations.

(1.2) Purpose of Baseline Study

The purpose of this study is to develop and select a particular reference scenario for each greenhouse gas component of the Gemina Project and to explain the reasons for the selected baselines in a transparent manner.

The purpose of the Baseline Study is achieved by:

(a) defining and evaluating possible reference scenarios (baselines) for each GHG component of the Gemina Rice Husk Project,

(b) selecting the most appropriate baseline for each GHG component,

(c) defining, to an adequate degree of detail and in a transparent manner, the selected baselines,

(d) justifying the use of the selected baselines for estimating GHG emission reductions attributable to the Project,

(e) predicting the GHG emission reductions that the Gemina Rice Husk Project is expected to create.

(1.3) Baseline Selection Concepts

In order to quantify the emission reduction benefit of a CDM project a rational base case, or sequence of cases, which define the emissions of GHG that would have occurred in the absence of the proposed project, needs to be determined. The base case is referred to within the CDM procedure, as the baseline. It is a set of future circumstances that are

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altered by the implementation of the proposed project. It can neither be directly observed nor be proved to be correct beyond doubt and has been called a “counterfactual construct”. When performing a baseline study, several possible baselines are generally identifiable. The aim of a baseline study is to select the baseline that reflects the most likely circumstances that would have occurred in the absence of the proposed project.

Since binding rules for the selection of project baselines have not yet been finalized by the UNFCCC Parties, baseline methodology and selection are currently being based on application of logical argument, as well as on the advice and examples provided by those already active in this field. To ensure a high probability that the GG and its GHG reductions will be accepted under Article 12 of the Kyoto Protocol, the selected baseline must, of course, be chosen so that a reasonably accurate prediction of GHG reductions can be expected. The baseline should be a conservative guess and should also be able to accommodate future changes1.

1 The Prototype Carbon Fund Baseline Study for the GHG component of the Liepaja Regional Solid Waste Management Project. www.prototypecarbonfund.org

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http://www.prototypecarbonfund.org/


(2) Existing Rules for Baselines

Although definite rules and modalities for CDM projects under Article 12 of the Kyoto Protocol do not yet exist, the Kyoto Protocol indicates criteria that baselines will need to meet in order to be acceptable:

– In Article 12. 5 of the Kyoto Protocol refers to the baseline issue as follows: ‘(b) Real, measurable, and long-term benefits related to the mitigation of climate change; (c) Reductions in emissions that are additional to any that would occur in the absence of the certified project activity’.2

The Kyoto Protocol establishes the requirement that Joint Implementation (JI) and CDM projects may only count emissions reductions that are ‘additional’ to what otherwise would have occurred in the absence of the certified project activity’. This process is termed ‘additionality’.

2 The Kyoto protocol Article 12.5c – Kyoto Protocol to the United Nations Framework Convention on Climate Change – www.unfccc.com

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(3) Principle Methodologies for Baseline Selection

(3.1) Baseline Methods

Baseline methodologies generally fall into two categories: Standard-Orientated and Project Specific.

(3.1.1) Standard-Oriented methods

The Standard-Orientated methods (also described as a top down baseline, multi-project baseline, generic baseline or bench mark) propose one baseline for a particular class of project. These methods are based on aggregated information derived from a large number of possible cases. Such baselines often have to be agreed through a political process and are applied at a national or regional level to act as the reference for a number of projects. They are expensive to develop and place a heavier burden on prior research and political decision making than other methods.

Standard-Oriented methods should, by their nature, be transparent and simplify comparability of projects from a GHG emission reduction perspective. They also tend to simplify baseline determination and reduce transaction costs and risks for the project developer/investor. A main criticism is that the results are not generally a true reflection of the actual emission reductions for a specific project.3

(3.1.2) Project-Specific methods

Project-Specific methods develop an ad hoc baseline for each single project by using all relevant information available for the particular project. Project-Specific baselines tend to be more expensive for the project developer.

Project-Specific baselines can be further categorised into either ‘Comparison Based’ or ‘Simulation Based’ approaches. A Comparison Based approach would be carried out using a control group. A Simulation Based approach may be carried out by investment analysis or a scenario analysis. A Project-Specific baseline is likely to be more accurate at the project level than the Standard-Orientated method. The approach is rooted in facts that can be observed at any time of the projects design or during operation.

Control Group Approach:The Control Group Approach works by identifying a town, region, country that is comparable to the area and the circumstances that prevail in the place where the CDM project is proposed. The ‘Proxy’ area is used to monitor developments in the absence of the CDM intervention. It is claimed to be useful for projects with a large number of units.

3 The Prototype Carbon Fund – Baseline Study Chile: Chacabuquito 26MW Run of River Hydro project and Liepaja Baseline Study (see footnote 1)

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Investment Approach:The investment analysis approach seeks to simulate the investment decisions that would be taken in the absence of a carbon purchase agreement. The approach attempts to identify all possible project alternatives. The primary assumption in this methodology is that profits maximisation is the primary driver for commercial, private sector projects (and that net benefit maximisation is the main driver for public sector projects). Using this approach, a baseline is selected based on highest internal rate of return (or least cost).

Scenario analyses:The scenario analysis attempts to make the case for a particular baseline by plausibly describing and explaining the factors impacting on project decisions and thereby systematically excluding all baseline possibilities but one.

(3.2) Selection of Baseline Methodology

Not all baseline methodologies are equally practical for all types of projects and circum-stances. The selection of the methodology for a particular project needs to take account of: project type4 and technology, data availability, project size, political acceptability and macro-economic developments. The relevance of these categories to the GG are considered to be:

– Project type and technology. Most standard-oriented, investment analysis and scenario description methods can be used for an energy type project such as GG.

– Data availability is crucial for all baseline methods, but host country specific data needs may vary for individual methods. Investment analysis requires project, sector and county specific data on risks and other factors and project-specific data, (e.g. on project costs), which may be confidential and hence not available. For GG most data required has been made available.

– Project size is another important factor in baseline analysis as indirect effects will likely depend on size. For a few small projects, determination of indirect effects may be less relevant than for larger projects. GG is a single, small project.

– Macro-economic developments and political decisions, for instance regarding a host countries’ energy policy, can be a source of great uncertainty regarding the validity and acceptability of project baselines. While this risk exists the small size of GG and relatively predictable effects suggest that the uncertainty is not a major factor.

4 Project types can be grouped into (a) energy supply project, (b) demand side management and end-use projects, (c) transport, (d) waste management, (e) emissions from agriculture, (f) carbon sequestration projects.

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(3.3) Common Baseline Issues

There are several common issues that the selection process of baseline methodologies should address. They are: 5

– Constant or dynamic baselines: A baseline is constant if either constant emissions or a constant emissions benchmark are assumed throughout the lifetime of the project. A baseline is dynamic if baseline emission levels change for other reasons than changes in activity levels or if a changing benchmark is used.

– Baseline time horizon: Baselines can be defined for different time horizons over the lifetime of the project. In particular, (a) full project duration, i.e., until the end of the technical or economical lifetime of the project; (b) baseline revisions in case of major ‘surprises’, for instance economic or policy shift; (c) until next periodic revision (e.g., every 5 years), (d) baseline horizon distinctly shorter than project lifetime (e.g. a fixed number of years). Short time horizons and/or frequent baseline revisions can increase the accuracy of CER estimates. However, the downside is the increased uncertainty of the revenue stream from sale of CERs and of increased burden of higher overall cost for the baseline work. Both of these effects will tend to decrease likelihood of implementation of marginally commercial projects.

– Baseline revisions can occur when a recalculation of the baseline shows serious deviations from the previous baseline. Recalculations may involve revised parameter values while applying the same methodology or a different methodology altogether. Baseline revisions can be pre-announced and prompted by pre-defined events, or they can be initiated by ad-hoc decisions to address unexpected developments.

– Leakage describes indirect emissions that occur outside of the defined project or sys-tem boundary. Indirect emissions can occur in both the baseline project and the CDM project and must be determined in the same manner. The chief reasons for leakage are technical system effects, e.g., the power grid, or economic system effect, e.g. increased coal use following lower prices induced by fuel-switching projects. Leakage effects need not always be negative.

– Macro-economic policies and developments such as market regulation, energy subsidies, or an economic crises can impact baseline determinations in an important way, because they can drastically modify the circumstances, scenarios and parameters used in baseline determination and may lead to GHG emission reductions which would otherwise be included in the baseline.

– Transparency of baseline determination is crucial for the credibility of JI and CDM projects and the long-term viability of these mechanisms. It requires access to relevant data and assumptions plus an explanation of the reasons for choosing a specific baseline methodology. It should allow non-specialists to understand how the baseline was determined.

5 For more details see: Axel Michaelowa (1999), Template for baseline studies for World Bank AIJ, JI and CDM projects, draft 1999.

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(4) Description of Gemina Rice Husk Project 6

(4.1) Project Location and Country Background

The Gemina rice and flour mill site is located on the outskirts of Chinandega, Nicaragua. The site has direct access from a major highway. The site is located adjacent to the Nicaraguan Electricity Company’s (ENEL) 15 MW Chinandega Power Plant and substation. The substation provides an interconnection between the state transmission system at 69 kV and a Medium Voltage (MV) busbar at 13.8 kV to supply the local distribution system.

General country information and a location map showing the location of Chinandega are included in Annex 1.

(4.2) Gemina Rice and Flour Mill

(4.2.1) Basic Operational Characteristics

The Gemina rice mill is normally operated for 24 hours per day, 5.5 days per week throughout the year (6,864 hours per year). The mill is currently designed to mill up to 9 tonne paddy/hour. Recently Gemina decided to expand milling capacity at the Chinandega site by relocating the Molinos El Pacifico mill to that site.7 When these changes are complete in 2002, the Chinandega complex will have a capacity to mill 18 tonne paddy per hour.

In 2001, the Chinandega mill processed 44,000 tonne of paddy and produced approximately 8,000 tonne of husk. After 2002, when Molinos del Pacifico Rice Mill has been transferred to Chinandega the husk production is expected to approach 25,000 tonne/year.

The flour mill normally operates for 24 hours per day and 26 days per month. The mill is currently designed to mill 5.2 tonnes of wheat per hour. The flour mill has a current demand of 660kW and a consumption of 305,000 kWh per month. Hence if operated normally throughout the year the annual consumption will be 3,660,000 kWh. Gemina plans to expand the capacity of the flour mill. The new equipment will use an additional 246 kW. Electrical demand will therefore increase by 197kW and by 1,249,116 KWh/year.

6 All information for section 4 is from ‘Feasibility Study, Gemina Power Plant, Chinandega, Nicaragua, November 2001, Bronzeoak Corporation’

7 The Molindos Pacifico mill is currently located some kilometers distant from Chinandega in Chicigalpa

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(4.2.2) Electrical Consumption and Cost

For the period July 1999 through April 2000, the average hourly consumption of electricity (month total divided by number of hours in the month) at the Chinandega mill complex varied from 264 kW to 419 kW (average 354kW). The annual electrical consumption, at that time, is estimated as 1,000,000 kWh and the paddy milled about 18,000 tonne/year.. More recently, the rice mill consumption has increased to 1,600,000 kWh/year. The current consumption at the Molindos Pacifico Rice Mill is 1,200,000 kWh. After the Molindos Pacifico plant is moved to the Chinandega site, the combined consumption is estimated to be 2,800,000 kWh.

After the currently planned expansions at the Chinadega site, the maximum demand of the rice mill and flour mills is expected to increase to 1450kW and the electrical use to about 8,000,000 kWh/year (2,800,000kWh from the rice mill and 4,909,116 kWh at the flour mill).

In 2000, Gemina paid an average of US 11 cent/kWh including IGV (similar to VAT in Europe) for electricity purchased from the local distribution company. Discounting and deducting the IGV, which Gemina can eventually recover, the net price was 9.65 cent/kWh. The supply of power is somewhat unreliable and the price is highly dependent on the world price of oil. As this report is being prepared the privately owned Nicaragua distribution companies are seeking price increases to compensate for the increased oil price, which has caused the cost of wholesale electricity to rise.

(4.3) Proposed Power Plant

The proposed project consists in the installation of a 1575 kWe rice husk power plant. The capacity is based on a fuel consumption of 2.75 tonne/hr. Two main operating modes are considered in this report. They are:

- Low operation mode

- Optimal operation mode

For the low operation mode, the GG is assumed to supply only on-site loads and not to sell any excess electricity via the Nicaraguan grid or distribution systems. This means that the plant load varies over a wide range, varying as demand from the on-site loads varies. This is a deliberately conservative case and, in keeping with this intent, under the low operation mode no rice husk ash sales are included.

For the optimal operation mode, the GG is assumed to supply the on-site loads as in the low operation mode plus sell all excess electricity. This means that the plant runs at design load for all operating hours. In this Case, 50% of the rice husk ash is assumed sold to cement companies and substitute for cement on a 1:1 ratio.

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For the low operation mode, the annual electrical quantities and husk consumption are estimated to be:

- Annual net production 8,000 MWh

- Annual fuel use 15,365 tonnes

(Fuel use is estimated from the design consumption of 1,575 kWh from 2.75 tonne plus 10% to allow for decreased efficiency at low loads).

For the optimal operation mode, the annual electrical quantities and husk consumption is estimated to be:

-12,420 MWh total net output from GG

- 8,000 MWh portion of net output used on site (excluding self use of GG)

- 4,420 MWh portion of net output sent to third party

- Annual fuel use 21,700 tonnes

(The total electrical output is based on operating at 1,575 kWe for 90% of the hours per annum. The fuel use is based on 2.75 tonne/hr for the same number of hours).

The technology proposed is based on the conventional boiler/steam turbine (Rankine) cycle. The husks are fed to the combustor and burned to produce heat. The hot gases then pass to a heat exchanger (boiler) where water is boiled under pressure. The resultant steam is passed to a steam turbine which drives an electrical generator. At discharge from the steam turbine, the steam is condensed and recycled to the boiler.

This basic technology has been used commercially for more than 100 years and has been employed with a wide range of biomass fuels including rice husks.

The proposed plant design uses a separate combustor and 20 bar heat recovery boiler. The combustor has an un-cooled, refractory lined, combustion chamber from which the hot gases travel through a labyrinth path before entering the heat recovery boiler. This ensures good combustion control and avoids problems that can arise from direct exposure of high temperature flames on the boiler tubes. The rice husks are fe whole to the primary combustion chamber which eliminates the need for pre-grinding.

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After the heat recovery boiler, the hot gases pass through a mechanical dust collector before being exhausted to atmosphere by a stack. The main design data is:

Fuel Input 2,750kg/hr Fuel Moisture Content 10 % Fuel HHV 14,235 kJ/kg Generator Output (gross) 1,750 kWe Generator Output (net 1,575 kWe Operating Hours 7,884 hr/yr (90% capacity factor)

(4.4) Environmental Impacts of the GG

The GG project will:

replace electricity that would otherwise be generated by fossil fuel, thus reducing the Carbon dioxide (CO2) emissions from those fossil fuels.

substantially reduce the open dumping and burning of rice husks from a large rice mill. The rice husks burned by the power plant will reduce the total husks that are disposed to open landfill. In a ‘business as usual scenario’ the rice husks are dumped and then burnt after six months. Dumping and burning emits methane (CH4 ) and nitrous oxide (N20). These emissions are measured in this study.

The reduced dumping will also lessen other environmental nuisances such as fugitive dust, smoke and traffic impact.

Introduce the technology of using rice husk ash as an additive to cement for substitution and to improve concrete properties.

Reduce Carbon dioxide (CO2) emissions from cement production

Demonstrate the possibility for commercially viable biomass renewable energy projects in Nicaragua and thereby act as a reference for additional plants both at other rice mills and at other locations, in Nicaragua and in other developing countries, where large quantities of biomass are produced.

Provide capacity building in CDM related activities.

Provide technology transfer, create skilled jobs and commercial investment.

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(5) Nicaraguan Issues Related to the Baseline

(5.1) General Issues

(5.1.1) UNFCCC and Kyoto Protocol requirements

Nicaragua has signed and ratified the Kyoto Protocol.

In line with Kyoto Protocol provisions, emission reductions must be transferred by the host country. In this context, the GG has been authorised by the Nicaraguan Ministry of Environment and Natural Resources (MARENA) and a letter confirming this was made available to the PCF. 8

(5.1.2) National legislation

Except for legislation related to deregulation of the energy sector and support for Kyoto Protocol that is discussed in the following sub-sections, no relevant Nicaragua legislation regarding the proposed project has been identified.

(5.1.3) Energy Sector and Climate Change

The Nicaraguan Government, acting through MARENA, issued an official communication regarding climate change policies in the framework of ‘The Environmental Plan 2001-2005’.9

The government is planning to create an ‘International Carbon Trade Office’ (ICTO)10

which aims to sell 300,000 tonnes of carbon over the next 3 years, in line with the framework of agreements established under the Kyoto Protocol.

The office will be run under the authority of MARENA but in coordination with the Central Bank, Export office and Commerce minister. It will support MARENA in the renewal of the Nicaraguan GHG Inventory and actively promote new CDM projects. Other key roles for the office will be to develop an ‘Information & Dissemination programme’ to improve national knowledge of impacts and effects of Climate Change (aimed principally at primary school level.); promote strict regulations to diminish GHG emissions; promote the adoption of clean technologies and finally provide incentives for

8 Endorsement Letter sent on 17th April 2001 from Roberto Stadthagen Vogi – Minister of MARENA9 Official Journal Gaceta Nº 44 (02-03-2001). Decreto Nº 25-2001 Política Ambiental y Plan Ambiental de Nicaragua 2001-200510 Personal communication: Mario Torres- Nicaraguan Representative for CDM Bronzeoak


good land management practices through programmes supporting organic agriculture, reforestation and forest management.

(5.2) Issues Applicable to the Electrical Generation Baseline

(5.2.1) Legal Constraints

Nicaragua has a deregulated power supply system. Participants in the supply system are required to comply with a complex set of regulations which were designed for utility size generating plants. Within this system, private companies can build new power plants and sell wholesale electricity based on a daily, competitive market process. As an alternative to the wholesale electrical market, producers can sell electricity to ‘Large Consumers’ or to distribution companies (suppliers of electricity at retail).

The smallest block of electricity, which can be offered via the wholesale competitive market, is presently 5 MW. Private power plants smaller than this are left with only three market options for selling electricity – the distribution company, large consumers or large generators. Since there are is only one distribution company (two exist but both owned by the same holding company) and very few large consumers or generators, a power plant under 5 MW has very limited options in terms of finding a buyer. Unlike many countries which have sought through regulatory or fiscal policy, to encourage renewable energy, no policy of this type currently exists in Nicaragua.

More information about the electrical supply system in Nicaragua is provided in Annex 2.

(5.2.2) Technical constraints

There are no technical constraints other than the common problem of predicting the cost of generation from other current and future generating plants in Nicaragua.

(5.2.3) Political constraints

There is no obligation on any state owned or privately owned electrical producer, transmission service supplier, distribution service supplier or end user to support renewable energy. In addition, there are no special fiscal or other support mechanisms that act to enhance the commercial viability of renewable energy. Since the smallest block size for electrical sales into the wholesale market is currently 5 MW, small renewable power plants are at a disadvantage compared to larger utility sized, fossil fuelled power plants.

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(5.3) Issues Applicable to the Dumped Husk Baseline

(5.3.1) Legal constraints

Currently MARENA requires industries to comply with Law 217, Decree 45-94. The law requires industries to adopt an environmental plan. The Gemina mill currently adopted a programme of transporting the husk to one location and then, dumping, burning and burying the husk. This law is being revised and Gemina may need to revise their current environmental plan. (The renewable energy plant, will play a positive role in meeting environmental regulations).

(5.3.2) Technical constraints

Not only is the rice husk dump site a local nuisance, it also represents sources of the greenhouse gases methane and nitrous oxide. The quantity of methane emissions depends on the degree to which conditions, in the piles of dumped husk, favour anaerobic decomposition. First, the available oxygen in the piles is used in aerobic decomposition of organic material. This process lasts as long as the oxygen supply. At the surface this continues indefinitely but within the pile the aerobic decomposition changes to anaerobic after a fairly short period of time.

As anaerobic decomposition proceeds methane is released. The heat produced during the anaerobic process causes the internal temperature of the pile to increase. The temperature can increase to such a level that self combustion occurs with consequential release of products of combustion. Whether self induced or the result of deliberate burning at six month intervals, an important product of combustion is nitrous oxide.

Nitrous oxide is also formed during the first, aerobic stage of the process and occurs under mesophilic conditions (<40ºC). The emissions are primarily due to the microbial processes of denitrification. 11

In this baseline study conservative estimates for methane and nitrous oxide emissions from the dumped husk have been prepared following guidelines in the ‘World Bank GHG Emissions Handbook’ and also the IPPC (see footnote 23).

There are many technical variables which affect the amount of emissions given off by the piles including outside air temperatures and moisture content for example which will cause the emissions to vary. No studies have been performed in Nicaragua on the measurement of these gases and no directly relevant studies for rice husk piles have been found in technical literature.

The methane estimates have been based on the assumption that the same quantities of husk (15,000 tonnes) are dumped each year and that variables, which might effect the

11 TOR for a study on Methane and Nitrous Oxide Emissions from biomass waste stockpiles. General discussion and case study in Bulgaria (PCF plus Research – November 2001)

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quantity released, remain constant. A study carried out by MARENA12 estimates that the average temperature in Nicaragua will rise by 1.5ºC by 2020 and that precipitation will decrease by 14.5%. Influences such as these would tend to increase methane production because the average temperature of the pile would be higher. The Baseline Study does not take into account these global warming scenarios because the accuracy of the methane production is not considered to be sufficiently high to warrant adjustment for what is likely to be a second order of magnitude effect.

(5.3.3) Political constraints

There is a possibility that at some point in time environmental controls to restrict dumping and open burning will be put in place. If the husk is disposed to landfill sites and buried without burning, this will affect the GHG released and might justify a revision to the Baseline. The net effect could be to increase methane release to atmosphere (e.g. if the husk is buried but no provision is made for collecting and flaring methane gas produced in the buried pile).

Environmental regulations will be monitored over time in order to assess this situation with a view to revising the Baseline for dumped husk. However, bearing in mind the size of the project, no change is proposed before the second period (2013 to 2023) when the selected proxy plant may be revised.

12 Global scenarios Pacific Stream Watershed ‘based on climatic and socio-economic scenarios for Nicaragua during XXI, March 2001’.

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(6) Selection of Baseline Approach and Additionality of GG

The additionality of the proposed project is assessed with reference to paragraph 48 a) of the Marrakesh Accords:

“In choosing a baseline methodology for a project activity, project participants shall select from among the following approaches the one deemed most appropriate for the project activity, taking into account any guidance by the executive board, and justify the appropriateness of their choice:

a) Existing actual or historical emissions, as applicable”

The baseline scenario is built on the assumption that the status quo ante (no investment in power plant) continues to prevail and consequently, the prevailing practice of consuming electricity from the grid can be used to determine baseline emissions.

This approach is justified because of the high barriers to implementation the project has continuously experienced.

The PCF views that the application of a barrier discussion to demonstrate additionality of a project is especially appropriate to reflect the reality of small scale projects which are acknowledged to be particularly hampered by institutional, economic and social barriers. In this case, the heuristic scenario analysis also helps to simplify the baseline analysis of the small sized Gemina project. The methodology applied here may thus be viewed as a way to simplify baseline procedures for small-scale projects.

(6.1) Small Scale project

With its capacity of 1.575 MW, the Gemina Rice-Husk-to-Power Project clearly falls under the category of a small-scale renewable energy project of up to 15 MW as defined by subparagraph 6 (c) (i) of the Marrakesh Accords.

At its third meeting, the Executive Board agreed that for a project activity with more than one component to benefit from simplified modalities and procedures, each component shall meet the threshold criterion of each applicable type. Being also a methane and nitrous oxide reduction project, the direct emissions of the project must stay below the threshold of 15,000 kilotonnes of CO2eq per year as provided in subparagraph 6 (c) (iii). By feeding the rice husks into the power plant, the Gemina Rice Husk project reduces the amount of methane and nitrous oxide that would be released into the atmosphere if the rice husks were left to decompose in open piles and burnt periodically. After installation of the power plant, all rice husks will either be fed into the Gemina Power Plant or used as

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supplemental fuel in other power plants. Thus, no methane and nitrous oxide will be emitted in the project case. CO2 emissions that are released from burning the rice husks in the power plants are not counted here as they are stemming from a renewable source. Thus, the project also meets the criteria for small scale projects according to the definition of subparagraph 6 (c) (iii).

(6.2) Barriers to investment

For renewable energy and small scale projects many barriers to investment that do not apply to standard investments have been identified. Renewable energy technologies, particularly for small rural applications, face a great number of barriers as a result of which would appear to justify the assertion that the status quo ante (no investment in rice husk power plant) continues to prevail and consequently, the prevailing practice of consuming electricity from the grid can be used to determine baseline emissions. These barriers include price distortions, regulatory barriers and biases, lack of information, insufficient management capacity, inability to analyze non-traditional projects, higher perceived technology risk of the alternative technology, high transaction costs, high initial costs (inability to amortize, poor access to credit), and appropriation effects (investment benefits cannot be recovered by the agent that bears the costs).

Many of the above barriers have also proven to exist in the case of the Gemina Power Plant. More specifically these are:

Regulatory barriers to access the market for electricityThe smallest block of electricity, which can be offered via the wholesale competitive market is presently 5 MW. Private power plants smaller than that as the Gemina Power plant are left with only three market options for selling electricity – the distribution company, large consumers or large generators.

Since there is only one distribution company (two exist but both owned by the same holding company) and very few large consumers or generators, a power plant under 5 MW has very limited options in terms of finding a buyer. Unlike many countries which have sought through regulatory or fiscal policy, to encourage renewable energy, no policy of this type currently exists in Nicaragua. Also, there are no regulations in Nicaragua requiring that the concessionaire purchases small renewable or cogenerated power at fair rates as they exist, for example, in Costa Rica.

Waste biomass-fueled plants are normally planned on the basis of the volume of the available waste biomass because the fuel is near-free while the capital cost is expensive. In the original Gemina design, the output pattern of the biomass power plant was not a good match to the Gemina rice and flour mill electrical demand pattern. As it became clear after two years that no excess power sales arrangement could be concluded, Gemina decided to re-configure and operate its new combined rice and flour milling operations in a manner

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Chandra Shekhar Sinha, 03/01/-1,

Page: 1Saying “significant amount” implies we know how much methane will come out when rice husk is combusted. I suggest deleting the phrase.


that would levelize internal electricity demand and increase the internal utilization of the biomass energy from 30% of electric plant annual capacity to 70% of capacity. These changes impose a loss of operational flexibility on the core rice and flour milling operations of Gemina, and hence represent a cost to Gemina that is not reflected in the analysis of the relative attractiveness of the biomass power plant project alone. It is unlikely that Gemina would have pursued this option without the prospect of being able to obtain a secure and additional foreign exchange revenue stream in the form of carbon offset payments.

As a consequence of regulatory barriers to the access of electricity markets, the Gemina Power Plant has not been able to market the projected excess electricity. Project sponsors have been shopping for a third party buyer unsuccessfully for two years. A near fully-negotiated third party sales agreement was scrapped when the distribution concessionaire took a cross-holding in the target electricity buyer. The monopoly distribution concessionaire has not been interested in dealing with small generators and Gemina has unable to enter into credible negotiations on a power purchase agreement.

Competitive disadvantages of non-traditional projectsThere is a lack of precedents regarding the proper implementation and integration of small generators of renewable energy in Nicaragua. This has lead to events like the following:o The concessionaire has impeded GG's third party sales by attempting to charge low-

voltage distribution tariffs for power wheeling rather than the much cheaper and properly applicable high-voltage transmission

o The concessionaire has blocked independent generator’s attempts to connect power plants directly to third party consumers by claiming in court against privately owned wires that passed over the concession area.

Limited access to creditThe sponsors’ financial situation does not allow them to finance such a project entirely through equity. Given the following makes it doubtful that Gemina could attract financing:o Absence of a long-term power purchase agreemento High Country Risk Rating for Nicaragua, deemed to be the second poorest country

in the Western Hemisphere.o Foreign investment disinterest due to the project’s size.o Non-existing local investment for biomass or any other renewable generation assets

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(6.3) Evidence of the binding nature of these barriers

Strong evidence that these barriers are of binding nature is given by the fact that the Gemina power plant is the first-of-a-kind. No other rice husk generators exist not only in Nicaragua but in the whole Central American region.

Furthermore, the sponsors have unsuccessfully quested for financing for many years.

Therefore, we conclude this project is not part of the business-as-usual scenario, and reduces the amount of GHG emissions beyond what would have otherwise occurred.

(6.4) PCF assistance to overcome the barriers

Besides providing a secure revenue stream to the project the PCF involvement will lend credibility to the project and will trigger the interest of other financial institutions.

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(7) Establishing the Baseline for Electric Power Replacement

(7.1) Interconnected Electrical System and GG Interaction with other Generators

The west and central areas of Nicaragua, including Chinandega where the GG is to be located, are served by an integrated electrical system. Detailed information about the system including past and forecast installed capacity, generation, unit fuel rates, order of dispatch and emissions, is provided in Annex 2.

Currently, Gemina buys its electrical supply from the local distribution company, Disnorte, which obtains electricity from a number of generating units that feed the interconnected system. Disnorte is, by law, not allowed to generate.

After GG begins to operate, Gemina will buy its electricity from GG. This will result in Disnorte reducing the quantity it takes from other generators. This ‘replacement’ of generation will be higher than the amount that GG supplies to Gemina because in the current situation, Disnorte has to buy more than it sells to Gemina due to system losses. On average, the system loss in 1999 was 30% 13. This is predicted to fall to 13% by 2010 as a result of the improved accountability under the privatised and deregulated system. A portion of this loss is due to technical system losses (mostly transformer and line losses) and the balance is due to unmetered customers (e.g. illegal connections or customers who for whatever reason are not metered). Typically, technical losses amount to between 10-15% in well run utilities. For Nicaragua, a 10% technical loss would mean that the backing down effect of GG results in 1.1 kWh of reduced generation for every 1 kWh of supply by GG for use on-site by Gemina.

In addition to supplying Gemina, GG may be able to operate at a fixed output and sell ‘excess’ electricity (net plant output minus quantity supplied to Gemina) to off-site consumers. This is the optimal operation mode discussed in Section (4) of this study. If GG operates in this mode, the amounts sold off-site will vary according to the varying demand of Gemina. The off-site sales will also cause a ‘replacement’ in generation by a system connected unit. In this case, the replaced quantity of electricity will be essentially equal to the quantity sold off-site, the ‘excess’, because both the quantity sold and the quantity replaced will suffer similar system losses before reaching the final consumer.

The generators that will reduce output to effect the ‘replacement’ are almost always fossil fired – burning either Light Fuel Oil (LFO) or Heavy Fuel Oil (HFO). When burned these oil fuels release the GHG, carbon dioxide, to the atmosphere. This carbon dioxide is avoided by the operation of the GG and is an important component of the carbon credits that should be attributed to the GG under the CDM.

13 See INE web page www.ine.gob.ni ‘Gross Power generation’ Bronzeoak

http://www.ine.gob.ni/


(7.2) Electrical Supply and Demand

To define the scenarios for ‘business as usual’, in CO2 emissions from GG, four factors are important:

analysis of past trends in electrical supply and demand,

prediction of the future electrical supply and demand14,

the electrical system expansion options,

the comparative marginal cost of generation (current and future).

Insight into these factors can be gained by reviewing the recent past, examining studies of the growth of the Nicaraguan electrical sector, broad considerations of future options and generic information.

(7.2.1) Past Generation & Consumption

Table 1 shows that, over the ten year period, grid connected generating capacity increased by 64%, from 371 MW in 1990 to 609 MW in 1999. Over this period, 238 MW of new generating capacity was added. Of this 222 MW was oil fuelled plant capacity and only 15.8 MW, the co-generation plant at Nicaragua Sugar ISA (a large sugar mill), was non-fossil. The new oil fuelled plants use predominantly HFO. One diesel oil fuelled plant, the Gas Turbine at Las Brisas, was also added. However, this plant is dispatched much less than the HFO plants because its efficiency is much lower.

Table 1. Nominal capacity of electrical generation units in Nicaragua.

14 The projected demand for electricity and planned system expansion have been studied by two different national institutions. MARENA included its work in the “First National Communication for Climate Change” (MARENA 2001). CNE prepared the “Indicative Plan for the Electricity Sector 2001-2010” (CNE 2001). The two studies differ in their use of methodology, time periods and projected increases in demand and consumption. MARENA’s study considers total demand (grid and off grid) while CNE study examines grid connected demand. MARENA considered a 25 year period of time (1995-2020) using scenarios for low (4%) and high (7%) annual increases in demand. CNE studied four different scenarios during 2006-2010 period of time, assuming an increase of electricity consumption of 7.11% annually.

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Plants Power system Units 1990 1999Public owner MW Rated MW EffectiveNicaragua Steam, HFO 2 x 50 100.00 100.00Managua Steam, HFO 1 x 45,

2x 6 75.00 57.50

Central America Hydro power 2 x 25 50.00 50.00Santa Barbara Hydro power 2 x 25 50.00 50.00Wabule Hydro power 1 x 1.6 1.62 1.62Canoas Hydro power 1 x 1.8 1.79 1.79Las Brisas GT, Diesel oil 1x 25,1x36 0 66.00Chinandega GT, Diesel oil 1 x 15 15.00 15.00Ormat Momotombo Geothermal power 2 x 35 70.00 70.00Private ownersCensa Amfels IC, HFO 1 x 35 36.00Corinto IC, HFO 1 x 70 70.00Tipitapa IC, HFO 1 x 56.7 52.20Nicaragua Sugar ISA Co-gen., Bagasse 1 x 19.6 15.80Timal (Victorias) Co-gen., Bagasse 1 x 10 12.00Isolated systemsPublic interest Diesel oil power 10-21 units 7.80 10.37Private interest Diesel oil power 1 x 0.88 0.88TOTAL 371.21 609.15Source: INE 1999 annual report

According to the Nicaraguan Energy Institute (INE) annual report 1999, over the period 1995 to 1999, electricity generation has increased by 23.5%, from 1700 GWh in 1995 to 2100 GWh in 1999. In addition to generating for its own use, Nicaragua also imports and exports electricity with Costa Rica, Panama and Honduras. Imports have risen from 63 GWh in 1995 to 80.3 GWh in 1999 and exports have dropped from 77 GWh to 23 GWh in 1999. This suggests a slow trend towards increased net import of electricity.

Gross generation by plant type during the period 95-99, is showed in table Nº 2. Over the period covered, reliance on fossil fired generation almost doubled becoming 73% of the total. At the same time, renewable energy generation has decreased from 717 GWh (41% of the total) to 550 GWh (26% of the total). Figure 1 shows the breakdown of electrical production by fuel type in 1999. The full year breakdown for 2001 is understood to be very similar.

Table 2 .- Electricity Gross Generation by type of plant during 1995-1999 (GWh) Bronzeoak


Type of Plants Fuel Type 1995 1996 1997 1998 1999

Thermal (steam) fossil fuelNicaragua Fuel Oil 680.44 729.01 624.95 717.99 590.01Managua Fuel Oil 220.39 361.45 339.94 385.85 238.95Internal CombustiónCensa (IC) Fuel Oil 0.0 120.78 213.90 166.39Corinto (IC) Fuel Oil 0.0 129.74Tipitapa (IC) Fuel Oil 0.0 282.75Gas TurbinesChinandega Diesel Oil 22.75 2.17 17.50 39.48 18.98Las Brisas Diesel Oil 65.76 21.28 73.62 260.98 124.89Thermal(steam) biomassISA (St Antonio) Bagasse 0.0 30.80 35.88Timal (Victorias) Bagasse 0.0 29.44 29.32 28.20 19.01Hydroelectric (4) 406.91 430.71 407.14 295.56 393.26Geothermal (1) 309.55 276.50 208.75 120.53 102.14Isolated Sys. (2) Diesel Oil 21.50 13.46 14.22 17.23 21.45TOTALS: 1727.31 1864.02 1836.22 2110.52 2123.47

Source: Gross generation by type of plant (www.ine.gob.ni)

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Figure 1:- Generated electricity by fuel type 1999 (2,123 GWh)

(7.2.2) Future Electricity Production and Consumption-

Future electricity production and consumption was estimated in two recent studies by Nicaraguan government institutions.14 The studies produced similar but somewhat different results. Since the study by CNE used more detailed analysis, the results from the CNE study are presented in this report, for future projections.

Figure 2 Projected maximum demand for electricity (CNE Study)

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The scenario base for projected demand considers an increase of 4.49 % yearly on gross demand in energy (see Figure 2), 4.16% in maximum demand, 4.54% in net requirements, and 7.11% increase in sales of power. Using these growth rates, the demand in 2000 of, 2310 GWh is projected to increase to 3582 GWh in 2010. Similarly, the maximum total demand is projected to increase from 419 MW in 2000 to 629 MW in 2010.

In terms of a requirement for additional capacity, the study indicates a need for about 21MW of new capacity annually plus replacement capacity for any plant withdrawn from service.

This growth suggests that the GG capacity will have a limited effect on required capacity additions.

Plants which may be retired and possible dates are shown in Table 3. The Table indicates that the Nicaragua and Managua Power Plants (HFO, steam cycle) will be retired in 2008. However, in discussions that took place between a representative of the World Bank and CNDC15, the view was expressed that instead of retirement of these plants, refurbishment was more likely. The view was also expressed that future expansion using medium speed IC units using HFO was realistic. This is borne out by the expansions over the last few years and the size of the needed additions. These are too small for a utility sized coal fired plant which would be very unlikely below 100 MW. They are also small compared to typical smallest size utility combined cycle power plants which tend to start at about 250 MW. Smaller configurations are available but are less common unless special situations such as availability of natural gas or a need for cogeneration with process steam exists.

Table 3: Current capacity and scheduled retirement for plants – 2000

Plant name Type of fuel

Technology used

Nominal Capacity

Net Capacity

Initiation year

Retire-ment year

Momotombo Gas turbine 70 12 1983/1989Central America Hydro turbine 50 48 1965Santa Barbara Hydro turbine 50 46 1972Wabule-Canoas Micro turbine 3.4 3.4Nicaragua (1,2) Fuel oil Steam turbine 100 100 1976 2008Managua Fuel oil Steam turbine 57.6 45 1971 2009Tipitapa Fuel oil IC 55 50 1999 2014Corinto Fuel oil IC 73.6 70 1999 2014Chinandega Diesel oil Gas turbine 15 14 1985 2004Las Brisas 1 Diesel oil Gas turbine 26 25 1992 2013Las Brisas 2 Diesel oil Gas turbine 40 40 1998

15 Private communication from Charles Feinstein, World Bank, 2001. Bronzeoak


CENSA(Amfels) Fuel oil IC 32 30 1997 2014ISA Bagasse Cogeneration 19.6 12 1999Agroinsa Bagasse Cogeneration 10 4 1996 2001Total 602.2 499.4Source: Based on Initial Indicative Plan for the Electricity Sector CNE 2001, and Energy Based Study for First Communication in Climate Change MARENA 2000

(7.2.3) Comparative Marginal Cost of Generation

The cost to generate electricity may be conveniently divided into two main components: fixed cost and variable cost. The fixed cost component covers the recovery of the cost to build the plant and such other costs as do not vary with the quantity of electricity generated (e.g. operating staff costs). Variable cost is generally sub-divided into two sub-components: fuel cost and non-fuel variable cost. Fuel cost is separated from other variable costs for most fossil fuelled plants because it not only varies with electrical output but also with the price of the basic fuel (e.g. world price of oil). Non-fuel variable cost covers those remaining costs which vary with plant output such as consumables for operation and maintenance.

The relative magnitude of the fixed and variable cost components change with plant technology. Hydro power plants, which have inherently high capital costs but low operational costs have a high percentage of fixed costs but low variable cost. Once built, the operating costs are relatively small. Geothermal power plants are similar.

Fossil fuelled power plants tend to have fuel costs which are significant. The relative cost of the fuel component to the sum of the components may be as small as about 25% (e.g. a mine mouth coal fuelled plant) to as high as 75% (e.g. high speed diesel generator running on taxed diesel oil).

For biomass power plants the relative magnitude of the components can also vary significantly. When a biomass power plant has zero or low cost of biomass, it tends to be similar to a hydro-power plant with mostly fixed cost. When it has a fuel cost, it tends to be similar to a fossil fuel plant.

When new capacity is added to an electrical system the range of possible proportions of fixed to variable costs has an important influence on plant selection. For additions expected to provide base load supply (high operating hours annually) the total cost (variable plus fixed components) is important for selection. For additions expected to provide peak supply (low operating hours annually) the variable cost component is important for selection. When existing capacity is operated to balance demand for electricity from consumers supplied by the system, the relative variable cost determines which plants should run to optimize, to the lowest cost of production.

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When new capacity is added, the economic decision will normally be based on which plant type provides the lowest future cost of supply based on future predictions of system demand, variation of demand (daily and seasonally) and cost of fuel. Once new capacity has been added it becomes existing capacity and, all other things being equal, it is operated to match consumer demand according to its variable cost compared to alternative plant capacity. This means that a plant with high fixed cost but low variable cost will be operated for more hours than a plant that has low fixed cost but high variable cost. In other words, the priority order for dispatching each connected power plant to a system will be: the lowest variable cost plant first and then each plant in order of increasing variable cost. There are some situations where plants will be run ‘out of order’. These include: hydro-power when water quantities are limited (they will then tend to be run during peak demand periods), plants required to provide system stability and plants which have power purchase agreements that are ‘take-or-pay’ type (obligation to buy irrespective of whether power is cheapest available or not).

In the context of this baseline study, the distinction between total cost, fixed cost and variable cost is relevant to two main considerations:

- predicting the number of hours a particular plant will operate annually depends on that plant’s variable cost compares to the variable cost of other available plants,

- predicting which type of new plants will be added to the system depends on the relative total cost of alternative new plants available.

(7.2.4) Will GG be likely to operate without restriction once built?

Electricity produced by GG will have two main uses. First, a portion will be supplied to Gemina for on-site use. Second, the balance, not used by Gemina may be sold as excess to off-site consumers. To answer the question of whether GG will operate without restriction, we need to address both uses.

The electricity used by Gemina is being sold under a long term contract at a price generally lower, and in no case higher, than Gemina can secure from its local distribution company, as a retail customer. Since Gemina cannot buy lower priced electricity, there is a strong commercial incentive to ensure that Gemina buys all its needs from GG. There are additional incentives encouraging Gemina to continue these purchases. These include: the sale of husk by Gemina, avoidance in cost of husk disposal and participatory returns as a part owner of the power plant.

Any electricity sold off-site is likely to be sold at a price near the wholesale market rate for energy as established by the deregulated spot market. At the time this Study was prepared, it was uncertain whether a long term agreement to sell this excess could be negotiated. However, even if no contract exists and only the spot market price for energy Bronzeoak


is available, the fact that the marginal cost of producing the “excess” electricity will be low, and significantly lower than the variable cost of producing electricity by either the old steam power plants or newer IC units, ensures that, provided the GG is legally able to make such sales, it will have a strong incentive to do so.

Table 4 shows the comparison of variable cost of fuel for different plants. The full variable cost would include the variable cost component for O&M. However, this is generally quite small (typically $5/MWh or less) and can be neglected for the purpose of this comparison.

Table 4 shows that the range of variable fuel costs for existing oil fuelled plants varies between $23.8/MWh and $72.4/MWh. Whereas, the GG is expected to have a variable fuel cost of $5.3/MWh. The only sources of electricity with a lower variable price are the hydro-power and geothermal plants, which has a zero cost for fuel. The same situation applies to the bagasse fired cogeneration unit at ISA which also has zero fuel cost. However, the combined capacity of these plants is such that they are well below the lowest system demand and never become ‘marginal’ plants. In addition, the bagasse fuelled plant at ISA only operates for six months of the year and the hydro-power plants are restricted due to limited water supplies. Some expansions of these zero fuel cost plants are planned. ISA is adding 15 MW and Ormat16 is developing a new geothermal plant. At the same time, the existing geothermal power plant is losing capacity and another bagasse fuelled plant has recently closed due to bankruptcy of the host sugar mill Agroinsa (Victorias). For these reasons, it seems unlikely that GG will ever replace electricity from zero cost fuel units.

Concerning the fossil fuelled plant, in the unlikely event that world oil prices were to fall by 50%, the GG would still produce a positive cash flow from selling excess electricity, if licensed to do so, rather than reducing load to simply supply Gemina’s own use. This is not to say that GG would attract investment funds at a much lower sales price for the excess than the currently assumed spot market value. However, it does mean that once built and operational, there are unlikely to be adverse circumstances when it would be financially preferable for GG to stop producing at full design capacity.

From the above, we conclude that the production of CER’s, due to load replacement, is both secure from the certainty of operation of GG, and the generation replaced will be from HFO units. The remaining uncertainties are whether GG will operate in the low or the optimal mode, what plants the GG will replace when it operates and how these may change over its operating lifetime.

Table 4 Comparison of Variable Costs of Electrical Production for Selected Power Plants

16 ORMAT is a Israeli company operating in Nicaragua. This company has a contract with GEOSA to improve the Momotombo facility to reach 70 MW. Currently it is 12MW .

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Plant Name Type Cost of Fuel(US$/gal)

(1)

Conversion Efficiency

(kWh/US Gal)(2)

Fuel Cost of Electricity ($/MWh)

Managua Steam, HFO 0.42 13.4 31.3Nicaragua Steam, HFO 0.42 13.5 31.1Corinto(Enron) IC, HFO 0.42 17.6 23.8CENSA-Amfels IC, HFO 0.42 16.0 26.3Tipitapa IC, HFO 0.42 16.7 25.1Chinandega GT, LFO 0.63 8.7 72.4CentralAmerica Hydro any 0.0Mombotombo Geothermal any 0.0New CCGT LFO 0.63 18.0 35.0New IC HFO 0.42 19.2 21.9GG Biomass $3/tonne 571 kWh/tonne 5.3Notes: (1) Fuel costs are typical for 2000.

(2) Conversion efficiencies for operating plants from INE data.(3) Conversion efficiencies for new plants and GG are estimated by Bronzeoak.

Table 5: Comparative cost of generation, merit order for dispatch & carbon dioxide emission rates

Plant nameand unit #

Variable Cost

($/MWh)

Fixed O&M cost

($/kW-year)

DispatchMeritOrder

Gross generation

(GWh)

Specific generation(kWh/US

Gal)

CO2

emission(kgCO2/kWh)17

Momotombo 45.80 0 Must run 120.7 geotherm 0Central Am. n/a n/a 1 120.7 hydro 0Santa Barbara n/a n/a 1 81.2 hydro 0Canoas/Wabule n/a n/a 1 2.3 hydro 0Nicaragua 1 2 34.5 17.50 4 468.1 13.5 0.843Managua 3 35.0 17.50 7 160.7 13.3 0.855Managua 4 35.5 19.50 8 22.4 15.0 0.759Managua 5 34.5 19.50 5 30.8 15.0 0.759Tipitapa 26.4 176.80 3 382.6 16.7 0.681Corinto (Nerón) 25.3 29.02 1 477.9 17.5 0.657Chinandega 83.2 14.63 10 3.7 8.7 1.139Las Brisas 1&2 57.9 16.00 9 53.8 12.5 0.794CENSA-Amfels 50.4 (3) 240.00 6 138.4 16.0 0.712ISA 1.8 196.00 2 27.2 biomass n/aAgroinsa n/a n/a n/a 6.3 biomass n/aGemina 11.3 biomass n/aSources and Note: (1) Plant operating and cost data from INE and CNDC Load Dispatch Center for 2000

17 See Annex 3 for the ‘Determination of CO2 emissions (kg C02/kWh) for Proxy Plants Bronzeoak


(2) Emission factor was estimated using fuel data from Kemp’s Engineering Handbook (3) The variable cost value for CENSA appears to contain an error.

(7.2.5) Plant Costs, Dispatch Order and Emission Rates in 2000

Table 5 includes plant operational data from INE and CNDC. Data in the first two appear to contain inconsistencies but are included for information. The significant data in the table from the perspective of this study is in column seven where the carbon dioxide emission rates for the fossil plants are provided.

(7.3) Time Dimension of Selected Baseline Scenario

The proposed project is expected to generate emission reductions throughout a design lifetime of 25 years. Given the maximum crediting period under the CDM the project can potentially generate emission credits over 21 years. During this time, baseline emissions from the power sector will follow a time profile, which may include shifts in the baseline scenario. For instance, existing electric generation capacity may be decommissioned, and new power plants constructed. This, may result in lower emissions from the displaced fossil unit at each hour of operation of the GG. The displacement could be rigorously assessed by an ongoing day-by-day analysis of the Nicaguan grid operation and regular updating of the emission characteristics of the displaced plants. However, such assessment work would be demanding and costly. In addition, the information required to perform the analysis is not currently available to the public and would not necessarily be available to the owners of the GG. Instead, a simplified approach is used which accommodates updating of the Baseline Scenario at a predetermined future date should circumstances change significantly.

(7.4) Electrical System Expansion Scenarios – Period 2003-2012

(7.4.1) Plausible Scenario

As explained in Section 7.2.2 the maximum system demand is predicted to increase from 419 MW in 2000 by about 21 MW per year. The generating net capacity in 2000 was 499 MW (Table 3). A typical reserve margin for an electrical system is 15-20%. Using this range of values suggests that the current net capacity should be in the range of 482 MW - 503 MW. This is 5 to 17 MW lower than the actual current net capacity. Allowing for the 21 MW/year growth in demand, we conclude that additional capacity will be needed within the next 1-2 years to avoid falling below the reserve criterion.

Based on information provided by various sources, additional capacity will come on line in 2002. The ISA sugar mill will increase its available export capacity from 12 MW to 27 MW but is still only expected to operate during the six month milling season. At the same time the Agroinsa (Victorias) sugar mill has ceased to operate and its capacity of 4 MW is no longer available. The output of the geothermal Mombotombo Power Plant is also being restored. This has fallen from an original design value of 70 MW to a current value Bronzeoak


of 12 MW. Reinstatement, will increase available capacity by 58 MW. Finally, the currently 30 MW CENSA(Amfels) bunker fuelled IC plant is expected to increase capacity to 57 MW. The net effect of these changes will be to add 96 MW to the total net capacity shown in Table 3. Taking into account the small overcapacity in 2000, this would be enough for about 6 years, therefore, it can be expected that the basic structure of the power generation system will not change significantly during the period through to 2008.

Table 6 shows the capacity available to the Nicaraguan system arranged in order of economic merit with the lowest marginal cost first. The table can be used to provide an indication of the marginal plant that GG would be likely to effect when GG operates. While the cases considered do not cover all situations or show fully the complex daily interplay between demand variations and available capacity, they do allow some general conclusions concerning the marginal plant that GG will displace based on the system capacity in 2000.

Table 6 Cumulative Capacity as System Demand Increases – 2000

Plant Fuel Effective PlantCapacity(MW net)

CumulativeCase (1)

Cumulative Case (2)

CumulativeCase (3)

Momotombo Geoth. 12.0 Y 12.0 Y 12.0 Y 12.0Nic. Sugar ISA Bagasse 12.0 Y 24.0 Y 24.0 N 12.0Central America Hydro 48.0 Y 72.0 Y 72.0 N 12.0Santa Barbara Hydro 46.0 Y 118.0 N 72.0 N 12.0Wabule, Canoas Hydro 3.4 Y 121.4 Y 75.4 N 12.0Corinto (Enron) HFO 70.0 Y 191.4 Y 145.4 Y 82.0Tipitapa (Coast’l)

HFO 50.0 Y 241.4 Y 195.4 Y 132.0

Censa (Amfels) HFO 36.0 Y 277.4 Y 231.4 Y 168.0Nicaragua HFO 100.0 Y 377.4 Y 331.4 Y 268.0Managua HFO 45.0 Y 422.4 Y 376.4 Y 313.0Las Brisas LFO 65.0 Y 487.4 Y 441.4 Y 378.0Chinandega LFO 14.0 Y 501.4 Y 454.4 Y 392.0 Import (max) 34.0 Y 535.4 Y 488.4 Y 426.0Notes:(a) Effective plant capacity is for 1999.(b) Plants are in order of priority from a lowest cost to produce perspective with lowest marginal cost plants first and highest last.Shaded cells show the range of available capacity covering minimum system load to maximum system load.(d) Import (max) is derived from the maximum monthly energy imported in 1999 and 2000 divided by the hours in that month.

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(e) Case (1) Indicates how the total available capacity increases as each plant is brought on line assuming all plants are available to run (Y).(f) Case (2) shows change to Case (1) when one hydro plant is not available to run (N) – it also simulates 50% restriction on total hydro capacity. (g) Case (3) shows change to Case (1) when the ISA plant and the hydro-plants are not available to run (N).

Case (1) shows the somewhat ideal condition with all plants available to operate. In these circumstances, the marginal plant on line, based on the 2000 maximum range of system demand (approximately 200 MW to 500 MW), would vary from the HFO Tipitapa through LFO Las Brisa. Case (1) also shows that the total renewable capacity in 2000 was well below the minimum system demand. Therefore, the possibility that GG would have displaced non fossil plant is very unlikely.

In these, best circumstances, GG would be expected to displace plants which vary in carbon dioxide emission rates ranging from 0.681 kg CO2/kWh (Tipitapa) to 0.843 kg CO2/kWh (Las Brisas). Frequently one or more plant will not be available, due to planned or unplanned maintenance, shortage of water for the hydro units and out-of-milling season at ISA.

Case (2) shows the situation with only 50% of the system hydro-capacity available. This simulates average conditions during the January to May 'wet' season, when hydro plant output is less than 50% of it full potential output. In these more typical circumstances, GG would displace plants which vary in carbon dioxide emission rates ranging from 0.712 kg CO2/kWh (CENSA) to 1.139 kg CO2/kWh (Chinandega).

Case 3 shows the situation when the ISA plant and all hydro plants are unavailable. This simulates the period June to November when bagasse is limited or not available (out-of-milling season) and ISA is either not run or restricted, and when the hydro plant output falls to less than 25% of potential output (dry season). The marginal plant, then, varies from Nicaragua through the highly inefficient GT plant at Chinandega. Even with imported capacity the maximum demand may not be met. For about 5 months annually, GG will displace plants with carbon dioxide emission rates from 0.843 kg/CO2/kWh (Nicaragua) to 1.139 kg/CO2/kWh (Chinandega).

As discussed earlier in this Section, capacity additions over the next few years are not expected to change the basic structure of the system capacity. From this, we can infer that, as the range of the system demand gradually increases from the present 200 to 500 MW new capacity will follow but not significantly exceed the growth rate. Therefore, the marginal plants in 2000 maybe expected to remain marginal plants until older plants are retired and new capacity is added at a rate exceeding the growth in demand.

The HFO plants Nicaragua and Managua are slated for retirement in 2008 and 2009 respectively. The NDLC expressed the view in 2001 that, although planned to retire in the Bronzeoak


2005-2010 time period, the Nicaragua Power Plant is more likely to continue in service18. Since then, both the Nicaragua and Managua plants have recently been sold to the Coastal Power Company. As a result investment will likely be injected into these plants to extend their operating lives. NDLC also expressed the view that system expansion will probably be by addition of HFO medium speed diesel units. These would be expected to have emission rates similar to the recent additions of similar plants, namely Corinto (0.657 kg/kWh) and Tipitapa 0.681 kg CO2/kWh. NDLC representatives suggested that the Nicaraguan plant is an appropriate choice of ‘proxy’ plant for GG.

For the above reasons, we conclude that GG should be modeled using the Nicaragua plant as ‘proxy’ for the emission rate of CO2 during the period, 2003-2012. This will mean that the emission rate to be used is 0.843 kg CO2/kWh.

(7.4.2) Implausible Scenarios

There is a remote possibility that, the ‘Central American Electric Interconnection System’(SIEPAC) might be built and could be used to supply Nicaragua with electricity from new, higher efficiency power plants located outside Nicaragua. Such electricity would be associated with a lower emission rate for CO2.

Another possibility, is that more new capacity is brought on line in Nicaragua such that older plants can be retired. While oil prices remain relatively stable, this is not likely because the capital cost of new plant is such that, continuing to run older, fully depreciated plant, still remains the lowest cost option.

Overall, we believe that the scenario based on using the Nicaragua Plant as ‘Proxy’ is a reasonable choice through to 2012.

(7.4.3) Electrical System Expansion Option 2013- 2023

Beyond 2012, influenced by the end of current power purchase agreements for Corinto, Tipitapa and CENSA and a perhaps a more integrated regional electricity market, a change to the marginal plants that GG is expected to replace is likely. A plausible option is that the overall efficiency of the system improves such that the current high efficiency plants fall in the merit order as new higher efficiency plants come on-line. While it is difficult to predict precisely what GG will replace, we believe it is currently reasonable to change the assumed ‘proxy’ to the HFO Tipitapa plant from 2013 onward. Table 5 demonstrates that it has high variable and fixed costs and a CO2 emission rate of 0.681 kg CO2/kWh.

Since, the MVP will also include a provision for reevaluating this choice in 2012, this pre-selection will not necessarily determine the final CERs earned by GG. Its purpose is

18 NDLC’s views given in this paragraph are based on personal communication to Bronzeoak related to a meetings between Charles Feinstein (World Bank) and representatives of the Nicaragua National Load Dispatch Center, Sept 26, 2001& Feb 19, 2002 Bronzeoak


mainly to provide a prediction of likely CERs and act as a basis from which to determine whether a revision is required from 2013.

(7.5) Implausible Scenarios 2013- 2023

In this period, electricity demand in Nicaragua could rise between 800-900 MW. The system could expand due to the availability of LNG, the development of a regional electricity market via SIEPAC or even coal from a nearby country (e.g.Guatemala). A higher international price for oil, would also have an impact. While the current relatively low price prevails, expansion using IC units is likely to continue. They represent a short lead time, convenient unit size additions and are cost competitive when natural gas is unavailable.

If the world price for oil increases, options such as a coal fired unit, the introduction of higher efficiency CCGTs burning HFO may well come into play. For the time being these scenarios seem implausible even in the long term.

(7.6) Use of Proxy Plant Approach

For displacement of electrical generation, the ‘Proxy Plant’ approach is chosen as the most appropriate option for GG.

Two proxies have been chosen. The first is based on the current operation of the Nicaraguan interconnected system and will be the proxy until end of 2012. The second proxy is based on the most plausible choice for the period 2013 to 2023 (end of GG design life).

Proxy plant – Emission Rate for 2003-2012:

Nicaraguan Plant Units 1& 2 – 0.843kg CO2 / kWh

Proxy plant –Emission Rate for 2013-2023:

Tipitapa 0.681 kg/CO2/kWh

As time passes the appropriateness of the second ‘proxy’ may become questionable. Therefore, the second ‘proxy’ will be subject to re-evaluation in 2012. At that time, if it is found that use of the second proxy is likely to overstate CERs for GG by more than 10%, a study will be performed to revise the proxy for the period 2013 to 2023.

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(8) Establishing the Baseline f or Reduced Dumping of Husk

(8.1) Husk Disposal Baseline

Control Groups:There are other rice mills in Nicaragua from which data could be drawn to work out what happens to the ‘rice husk dumps’ over time and what emissions are given off. However, there are no set rules for the disposal of husk and often the husks are dumped in more than one location, depending on the availability of sites for disposal. Assembling such information from other private rice mills would, at best, time consuming and at worst, impossible as owners might not wish to cooperate in providing information. Even if data could be collected, it might well be inapplicable to the GG case due to a range of uncontrollable variables.

Investment Analysis: An investment analysis approach is limited because there are few alternatives that offer a long term potential to provide a positive and secure cash flow for the husk as offered by GG. Certainly, some husk has been sold to the ISA sugar mill cogeneration units for use as fuel. However, as already discussed, use rice husks with their inherent high silica content in boilers designed for other fuels has been the cause of serious problems. This certainly brings into question the long term sale of husks as a supplemental fuel beyond the limited use that has occurred over the last two years. In addition, the ISA units are run for only about six months each year which limits the total husk that can be consumed.

For this GHG component an investment approach does not seem appropriate.

Scenario analysis:By plausibly describing and explaining the factors impacting on the disposal and management of the rice husk, the scenario analysis, is considered to be the applicable method to use in order to establish the Baseline for dumping rice husk. The disposal management of the husks is both specific to the Gemina company and the local area. Only one dump site is used and the husks are burned every 6 months.

(8.2) Past Husk Disposal Practices

Gemina advised that, until the last two years, virtually 100% of the husk was disposed to open landfills19.

19 Feasibility Study, Gemina Power Plant, Chinandega, Nicaragua, November 15, 2001, Bronzeoak Corporation

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Over the last three years some husk has been sold as supplemental fuel to a boiler designed to burn bagasse on a spot basis. Gemina advised that this accounted for about 5,000 tonne of the husk produced in 1999 and 20001. In 2001, the combined amount soldby the Gemina mill and the Molindo de Pacificos mill was 6,000 tonne20 . Husk is only sold as supplemental fuel for about six months when the sugar mill boiler is in operation.

The husks that are dumped are transported to a location approximately 3 kilometers from the mill site. The husks are dumped in piles that are up to 2m with an average height of about 1.5 m.

The dumped husk begin to decompose in a combination of aerobic and anaerobic processes. Periodically, self combustion of parts of the piles occur. After about 6 months of dumping, the decomposing and part burnt rice husk is burnt manually. Finally, the ashes are buried in trenches.

In other situations in the US and elsewhere, using rice husks as a supplemental fuel, either blended with other fuels or used alone, in a combustor or boiler that was not designed for rice husks, has resulted in problems due to erosion and fouling (deposition of ash on heat transfer surfaces). As a consequence, use of rice husks as a supplemental or replacement fuel for industrial applications has been limited. The long term sale of husks from Gemina as a supplemental fuel is, therefore, problematic.

(8.3) Disposal Scenario for Husk Dumping Baseline

(8.3.1) Husk Quantity

By 2003, the quantity of husk produced at the Chinandega site is predicted to increase to 25,000 tonne/year. The GG will consume 15,365 tonnes per year in the low operating mode or 21,700 tonnes in the optimal operating mode. Although the plant consumes different quantities of husk in each Case, if the power plant were not built, the rice mill would continue to produce 25,000 tonnes of husk annually. Currently, the Chinadega mill sells 5,000 tonne/year and the Molindos Pacifico mill sells 1000 tonne/year. To ensure a conservative Baseline, we propose to assume that, absent the GG and after the expansion at Chinadega, 10,000 tonnes of husk would have been sold as supplemental fuel. This would leave 15,000 tonnes/year of husk disposed to landfill. This the maximum amount that will be saved from being dumped by operation of the GG. Since, even in the low operating mode, the GG is expected to consume more than 15,000 tonne/year, the GHG emissions associated with the dumping of 15,000 tonne/year of husk will likely become CERs attributable to GG.

20 Private e-mail from Gemina to Bronzeoak, February 1, 2002. Bronzeoak


(8.3.2) Transport Related Emissions

Rice husks are transported from the mill by diesel-fuelled vehicles thereby creating carbon dioxide emissions. Although other transport modes for bulk material like husks, may be postulated for some future date, trucks running on diesel fuel have been the almost the exclusive choice in Nicaragua and, for that matter worldwide, for several decades. Therefore, for the business-as-usual disposal scenario, it is assumed that diesel fuelled vehicles similar to those currently used would continue to operate.

In 2001, the Chinandega mill produced 11,000 tonne of husk. The diesel fuel consumed to dispose of this quantity of husk was reported to be 6,640 US gal. This is the fuel used to transport the total quantity with a portion going to the sugar mill and the balance to the dump site. The breakdown between the two destinations is not known.

To estimate the diesel quantity that would be consumed, absent the GG, we propose to multiply 6,640 US gal by the predicted future annual husk production in tonne divided by 11,000 tonne. Hence:

Diesel consumption after 2003 (without GG) = 6640 x 25,000 / 11,000 = 15090 US gal

When the GG operates, we have discussed above how it can result in 15,000 tonne/year of husk not being dumped. To be slightly more precise, for every tonne of husk that GG consumes up to 15,000 tonne/year it will avoid the same annual quantity being dumped.

For both the low operating mode and optimal operating mode, with 15,365 tonne/year and 21,700 consumed respectively, the avoided use of diesel oil is:

15,090 x (15,000/25,000) = 9,054 US gal. = 34,270 litres

The above relationship can be converted into a more general form for use in estimating the litres of diesel oil avoided based on the quantity of husk consumed by the GG. The value is derived as follows:

34,270 (litres)/15,000 (tonnes) = 2.284 litres/tonne husk

This unit of specific avoided consumption can be used to calculate the avoided diesel, and hence avoided carbon dioxide, on a daily basis such as in the MVP, with the added qualification that it is used only up to 15,000 tonne husk consumed annually.

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(9) Establishing the baseline for substitution of rice husk ash for cement

Cement production is energy intensive and is a major source of greenhouse gases producing up to 2.4% of the world’s total carbon dioxide (CO2) emissions and approximately 8% of total non fuel based GHG emissions. In the US more than half of the carbon dioxide emissions from industrial sources originate from cement manufacturing.

Four basic materials are required to make cement: calcium, silicon, aluminium, and iron. Substrates of these materials are ground into a powder and heated in a kiln to about 2700°F (1500°C). While in the kiln, limestone (the predominant source of calcium) is broken down into CO2 and lime. The CO2 produced from this calcination process is driven off into the atmosphere.

CaCO3 + Heat = CaO + CO2

In addition, carbon dioxide is released from the fossil fuel used to supply the heat needed for the calcination process and electrical energy is used to grind the resultant clinker with approximately 5% gypsum (which controls the setting time), to produce cement. The net result is that on average 1 tonne of cement clinker produced, results in 1.25 tonnes of CO2

being released. Approximately, 40% of this is the result of calcination and the other 60% is the combustion produced from the fossil fuels supplying the energy for calcination .21 When Gemina burns husk about 20% of the husk will convert to ash by weight. Gemina will burn up to 15,365 tonnes in the low operating mode and 21,700 tonnes of husk per year in the optimal operating mode, resulting in approximately 3,073 and 4,340 tonnes of ash respectively every year.

The current production of ash from open burning of piles of husks is sporadic and the ash is not of a high enough quality for use in high strength concrete. From a study of the production and market availabilities for residual heavy ash performed by Bronzeoak, many existing purpose built incinerators and power plants that burn husk are able to sell the ash for use in the construction industry. Some sell close to 100% of their output others much less. In the case of new plants that are under development, all contacted by Bronzeoak were planning to sell the ash for beneficial uses.

21 www.holman.com/environment/greenhouse - Cement, Concrete and Greenhouse Gases.

1995 Intergovernmental Panel on Climate Change (IPCC), Working Group II, Pg 661)

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http://www.holman.com/environment/greenhouse


While it is anticipated that the ash produced by burning husks in the specially designed combustors of the GG will be of sufficient quality to be used as a partial substitute for cement in concrete production, it is unlikely that 100% of the RHA will be sold for this purpose.

The RHA produced may not always be acceptable to the concrete producers for reasons related to quality. There exists a possibility that due to poor combustion the level of unburnt carbon may be too high. There also exists the problem of keeping the RHA totally dry during periods of heavy rain. Finally, the RHA will be produced on a near continuous basis, so there may be times when no concrete producer is able to take delivery and the RHA has to be dumped.

For the purpose of the estimates presented in this report, we are assuming that no ash is sold in the low operating mode and 50% is sold in the optimal operating mode. We consider the low operating mode-assumption to be very conservative, particularly in a developing country where a lower cement quality may be acceptable and suitable for many non-load bearing tasks.

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(10) Indirect Emission Effects (Leakage) Indirect emission effects are changes in emission levels that are caused by the project but occur outside of the baseline and project boundaries. Indirect effects can be positive (decrease in emissions) or negative (increase in emissions or “leakage”). If indirect effects are significant, calculated emission reductions within the project boundaries must be corrected for leakage.

In the case of the Gemina project, sources for increased emissions due to leakage have not been identified. On the contrary, it seems more likely that the project will have a positive indirect effect on emissions. These include, reduced emissions from the transportation of fuel oil to the fossil fuel oil power plant that reduce generation when the Gemina project operates and the potential to act as a catalyst for additional biomass to energy projects in Nicaragua.

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(11) Calculation of Certified Emission Reductions

A detailed procedure for calculating of CER’s during the operation of the proposed project will be provided in the separate MVP document. The following is a summary of the procedure based on a monthly measurement period:

Measure the net electrical output exported to a third party(s) and the net electrical output supplied for use at the Gemina site (i.e. exclude electricity generated and used to operate GG).

Measure the husk quantity consumed by the plant over the same period.

Using the appropriate conversion factors, as determined by the Generation Baseline, calculate the quantity of carbon dioxide related to avoided generation by displaced electricity.

Using the appropriate conversion factors, as determined by the ‘Husk Disposal Baseline’, calculate the quantities of methane, nitrous oxide and carbon dioxide, related to husk disposal. Convert the quantities calculated in the previous step to equivalent quantities of carbon dioxide using the Global Warming Potential factors stated in the Baseline.

Sum the quantities of carbon dioxide from the two Baselines to produce the CER quantity for the measurement period.

Using the above procedure, project emissions for the project lifetime were estimated as shown in Section (13). The emissions are all expressed in terms of equivalent tonnes per year of carbon dioxide using relative Global Warming Factors to convert the quantities of methane and nitrous oxide quantities to equivalent carbon dioxide quantities.

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Carbon emission factor

(kg C/kWh)

Annual electricity production(kWh/yr)

1/1000(kg to

tonnes)

Carbon emission factor

(kg C/kWh)

Annual electricity production(kWh/yr)


(12) Estimated CERs Over Project Lifetime

(12.1) CER’s from Avoided Electrical Generation (Low operating mode)

(12.1.1) Emissions of CO 2 from electricity generation

Equation 3.3 of the World Bank GHG Handbook22 was used:

x x = (1)

Using the data discussed in table 3 the following were determined:

In addition, for electricity generated and used on-site, a factor of x1.1 (based on 10% loss) is applied, as discussed in section 7.1.

Period 2003 - 2012

Electricity use by Gemina

0.843 kg C02/kWh x 1.1 x 8,000,000 kWh/yr x 1/1000 = 7418 tonne CO2/yr

Period 2013 - 2025

Electricity use by Gemina:

0.657 kg CO2/kWh x 1.1 x 8,000,000 kWh/yr x 1/1000 = 5782 tonne CO2/yr

(12.2) CER’s from Avoided Electrical Generation (Optimal operating mode)

Equation 3.3 of the World Bank GHG Handbook23 was used:

22 World Bank (1998) Greenhouse Gas Assessment Handbook. Climate Change Series

Annual CO2

emissions (t/yr)

Annual CO2

emissions (t/yr)Bronzeoak

Annual fuel consumption

(kg/yr)

Annual CO2

emissions (t/yr)

Carbon emission

factor (kg C/kg diesel)

Combustion efficiency

(%)

Conversion factor

1/1000(kg to

tonnes)


x x = (1)

Period 2003 - 2012

Electricity use by Gemina

0.843 kg C02/kWh x 1.1 x 8,000,000 kWh/yr x 1/1000 = 7,418 tonne CO2/yr

Excess Electricity sales:

0.843 kg C02/kWh x 4,420,000 kWh/yr x 1/1000 = 3,726 tonne CO2/yr

Total: 11,144 tonne CO2/yr

Period 2013 - 2025

Electricity use by Gemina:

0.657 kg CO2/kWh x 1.1 x 8,000,000 kWh/yr x 1/1000 = 5,782 tonne CO2/yr

Excess Electricity Sales:

0.657 kg C02/kWh x 4,420,000 kWh/yr x 1/1000 = 2,904tonne CO2/yr

Total: 8,686 tonne CO2/yr

(12.3) CERS from Avoided Husk Disposal (Low operating mode)

(12.3.1) CER’s from avoided transport of husks

Equation 3.11 of the World Bank GHG Handbook1 was used, following guidelines discussed in case study 3.3 of the Handbook.

x x x = (2)

23 World Bank (1998) Greenhouse Gas Assessment Handbook. Climate Change Series Bronzeoak


Where: Conversion factor is the product of kg mol, of CO2 relative to kg mol. C (44/12) and kg/tonne (1/1000).

The annual consumption of diesel used for transporting 15,000 tonnes of rice husks is estimated at 34,273 litres/yr, discussed in Section (8). This was converted to kg diesel by multiplying by the density of diesel (0.83 kg/l):

34,270 l/yr x 0.83 kg/l = 28,444 kg/yr

For diesel, a carbon emission factor of 0.861 kg C/ kg diesel was used and a combustion efficiency of 98%.

28,444 kg/yr x 0.861 kg C/kg diesel x 98% x 44/12 x 1/1000 = 88 tonnes CO2/yr

Again, as in Section 8.2.2, this emission can be expressed as an avoided rate of carbon dioxide emitted per tonne of husk consumed. This is derived as follows:

88 (tonne CO2/yr) / 15,000 (tonne husk) = 0.00585 tonne CO2/ tonne husk

This specific rate of emission can be used to calculate the daily avoided carbon dioxide due to husk consumption by the GG.

(12.3.2) CER’s from avoided dumping of husks

Equation 5.1 of the IPCC report on GHG inventories was used24. This formula produces a time dependent emission profile that reflects the degradation process over time. The formula can be simplified for this study where the husk is only standing for six months before being burnt.

(1-e-k) x Q/2 x Lo = CH4 generated (tonne/yr) (3)

Where: k = 0.2 (source: IPCC GHG inventory23)Q = quantity of dumped husk per year

and

Lo = MCF x DOC x DOCf x F x CF (4)

24 IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. www.ipcc-nggip.iges.or.jp/gp/report

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Where: Lo = methane generation potential (mass methane/mass waste)MCF = methane correction factor, 0.4 for a default pile <5 m high (Source: IPCC)DOC = degradable carbon fraction in the husk, 36.2% from laboratory analysis. See Gemina Power Plant Feasibility Study..

DOCf = Fraction of DOC dissimilated (default 0.55) (Source: IPCC)F = Fraction of CH4 in landfill gas (0.5 default) (Source: IPCC)CF = molecular weight of methane relative to carbon (16/12)

Determining the methane generation potential by computing equation (4):

0.4 x 36.2% x 0.55 x 0.5 x 16/12 = 0.05309 Determining the methane (tonne) generated per year using equation (3):

(1-e.0.2) (=0.181) x (15,000 /2) x 0.05309 = 72.1 tonne CH4 /yr

Converting methane released per year to units of carbon equivalent tonnes

methane released (tonne/ yr) x FGWP = tonne CO2 equivalent (5)

Where:FGWP is the equivalent global warming potential of methane in terms of carbon dioxide (= 21).

72.1 x 21 = 1,514 tonne CO2/yr

In terms of husk consumed, the avoided emission can be expressed as:

1,514 (tonne CO2/yr)/ 15,000 (tonne husk) = 0.100 tonne CO2/tonne husk

Note: this relationship applies for up to 15,000 tonne/husk consumed per year. Above that amount, no further emission reduction is credited.

(12.3.3) CER’s from avoided open husk burning

Methane (CH4)

Firstly the annual carbon (t/yr) released by husk burning was determined as follows:

Carbon content of husk (%)

Quantity of husk burnt

(t/yr)

Annual carbon released

(tonne/yr)Bronzeoak

% Carbon released

as methane

Annual carbon

released(t/yr)

Annual nitrogen released

(tonne/yr)


x = (6)

The quantity of husk burnt (t/yr) was obtained from Section 8 and the carbon content of the husk was determined from laboratory analysis3:

15,000 tonne/yr x 36.2% = 5,430 tonne/yr

Then equation 3.9 of the World Bank GHG Handbook was used to determine the methane emissions from rice husk burning in t CO2 equivalent.

x x x = (7)

Where:– Conversion factor 1 is the molecular weight of methane relative to carbon,

(16/12)– Conversion factor 2 is the global warming potential of methane in units of CO2

equivalent tonnes, equal to 21.

The annual carbon released was derived from equation (6), and the carbon released as methane taken as 1.2% (Source: World Bank GHG Handbook), resulting in:

5,430 tonne/yr x 1.2% x 16/12 x 21 = 1,824 tonne CO2/yr

In terms of husk consumed, this avoided emission can be expressed as:

1,824 (tonne CO2/yr)/15,000(tonne husk) = 0.121 tonne CO2/tonne husk


Nitrous oxide (N2O)Firstly the annual nitrogen (tonne/yr) released by husk burning was determined as follows:

x = (8)

Methane emissions

(tonne CO2

equivalent)

Conversion factor 1

Conversion factor 2

Nitrogen content of husk

(%)

Quantity of husk burnt(tonne/yr)

Bronzeoak

Nitrogen released as N2O

(%)

Annual nitrogen released

(tonne/y)


The quantity of husk burnt (t/yr) is discussed in section 8.1 and the nitrogen content of the husk was determined from laboratory analysis25:

15 000 tonne/yr x 0.24% = 36 tonne/yr

Then equation 3.10 of the World Bank GHG Handbook23 was used to determine the nitrous oxide emissions from rice husk burning in t CO2 equivalent.

x x x = (9)

Where:– Conversion factor 1 is the molecular weight of N2O relative to carbon (44/28).– Conversion factor 2 is the global warming potential of nitrous oxide in units of

CO2 equivalent tonnes, equal to 320 (source: World Bank GHG handbook).

The annual nitrogen released was derived from equation (8), and the carbon released as nitrous oxide taken as 0.7% (source: World Bank GHG handbook).

This results in:

36 tonne/yr x 0.7% x 44/28 x 320 = 127 tonne CO2/yr


127 (tonne CO2/yr)/(15,000tonne husk) = 0.008 tonne CO2/tonne husk

(12.4) CER’s from Avoided Husk Disposal (Optimal operating mode)

(12.4.1) CER’s from avoided transport of husks

With respect to husk dumping, the quantity avoided by the Optimal operating mode is 15,000 tonne, the same as for the low operating mode. The amount remains unchanged because, in the optimal operating mode, 21,340 tonne of husk is burnt by the GG. This exceeds the 15,000 tonne limit that, without the GG, would have been dumped. 25 Laboratory Analysis – from the GBP Feasibility Study ,

N2Oemissions

(tonne CO2

equivalent)

Conversion factor 1

Conversion factor 2

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Therefore the avoided emissions are: 88 tonnes CO2/yr

Again, this emission can be expressed as an avoided rate of carbon dioxide emitted per tonne of husk consumed. This is derived as follows:

88 (tonne CO2/yr) / 15,000(tonne husk) = 0.00585 tonne CO2/ tonne husk

This specific rate of emission can be used to calculate the daily avoided carbon dioxide due to husk consumption by the GG.

(12.4.2) CERs from avoided dumping of husks

For the same reasons as explained in Section 13.4.2, the CERs will be the same as for the low operating mode, that is:

1,514 tonne CO2/yr

Again, in terms of husk consumed, the avoided emission can be expressed as:

1,514 (tonne CO2/yr)/ 15,000(tonne husk) = 0.100 tonne CO2/tonne husk

Note: this relationship applies for up to 15,000 tonnes/husk consumed per year. Above that amount, no further emission reduction is credited.

(12.4.3) CER’s from avoided open husk burning

Methane (CH4)

Same as for low operating mode: 1,824 tonne CO2/yr

Again, in terms of husk consumed, this avoided emission can be expressed as:

1,824 (tonne CO2/yr)/15,000(tonne husk) = 0.121 tonne CO2/tonne husk


Nitrous oxide (N2O)Same as for low operating mode:

127 tonne CO2/yr

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127 (tonne CO2/yr)/15,000tonne husk) = 0.008 tonne CO2/tonne husk


(12.5) CERS from substituted cement with RHA – Optimal operating mode only

Determining the annual quantity of cement/RHA mixture that can be produced using RHA from Gemina:

Assuming:0.75 tonne of CO2 per tonne of cement from energy use0.50 tonnes of CO2 per tonne of cement from calcining limestone1.25 tonnes of CO2 per tonne of cement total26

50% of RHA produced is sold for cement substitution

x =

4,340 (tonne/yr) x 0.5 = 2,170 (tonne/yr)

The total annual emissions factor for cement with RHA substitution is:

2,170 t/yr x 1.25 = 2,713 CO2/yr

26 1995 Intergovernmental Panel on Climate Change (IPCC), Working Group II, Pg 661)

Rice Husk Ash produced (tonne/yr)

0.5 RHA sold for cement substitution (tonne/yr)

Annual RHA production for sale x

1.25 tonnes of CO2

per tonne =Annual Emissions

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(13) Estimated CER summary for project lifetime The summary of the estimated CERs in tonnes of equivalent carbon dioxide per year over the lifetime of GG for the low operating mode and optimal operating mode are shown Tables 8 and 9.Table 8 Estimated CER’s for Low operating mode

Time period: 2003 - 2012 2013 – 2023Emissions/ activities:CO2 Energy 7,418 5,782CO2 Transport of husks 88 88CH4 Dumped husks 1,514 1,514CH4 Burned husks 1,824 1,824N2O Burned husksCO2 RHA

1270

1270

Total Baseline 10,971 9,335Project emissionsNet Reduction (tonne CO2 ) 10,971 9,335

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Table 9 Estimated CERs for Optimal operating mode

(14)Risks potentially affecting CERs and mitigation measures

Risk (1)

The cost of petrol may rise and increase the cost of operating machinery for burying the husk and ashes. Dumped waste might stay in piles longer time before self-combustion.

Mitigation (1):

This is a risk, which would tend to increase avoided emissions of GHG, thereby making the CER value derived from the Baseline lower than the

Time period: 2003 – 2012 2013 – 2023Emissions/ activities:CO2 Energy 11,144 8,686CO2 Transport of husks 88 88CH4 Dumped husks 1,514 1,514CH4 Burned husks 1,824 1,824N2O Burned husksCO2 RHA

1272,712.5

1272,712.5

Total Baseline 17,409.5 14,951.5Project emissionsNet Reduction (tonne CO2 ) 17,409.5 14,951.5

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true value. The Baseline tends to be more conservative. No mitigation is required.

Risk (2)

In the future a significant number of non-fossil generating plants could be installed i.e. Geothermal, hydropower and biomass. This would affect the generation composition of the grid and cause changes in the quantification of carbon dioxide emissions.

Mitigation (2):

The baseline will be reviewed at 2012 to evaluate the effect of new power plants and fuel types .If necessary the proxy for the second period (2013 to 2023) will be revised.

Risk (3)Rice husks could be diverted to other users and consequently change the ‘business as usual’ scenario.

Mitigation (3):The markets for rice husk in the Chinandega area are limited. The effect of this risk will be reviewed in 2012 and a revision to the Baseline for the second period made if necessary.

Risk (4)Rice milling becomes an unproductive business and operations are reduced or curtailed.

Mitigation (4):The GG might stop operating and would not then create CERs. In which case it would no longer receive revenue for the sale of CERs. However, this is a very remote possibility as the rice from Chinandega is in increasing demand as Nicaragua economic situation improves.

Risk (5) The GG is successful and encourages the installation of similar projects which creates competition for the rice husk supply.

Mitigation (5):GG receives its husk supply from its host under a legally enforceable contract. In addition, the host has a strong incentive, through electrical savings and participation in the project ownership, to continue to supply the husks to GG.

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(15) Additional sources of reference 1. MARENA, GEF, PNUD, 2001. Climate Change National First

Communication. MARENA Managua 125 pp2. OLADE, CEPAL, GTZ, 2000. Energía y Desarrollo Sustentable en

América latina y el Caribe: Guía para la formulación de Políticas Energéticas.

3. Johansson T, Kelly H, Reddy A, Williams R, 1993. Renewable Energy (Sources for Fuels and Electricity) Island Press, Washington DC 1160pp

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4. Quaak P, Knoef H, Stassen H, 1999. Energy from Biomass (A Review of Combustion and Gasification Technologies). World Bank Technical Paper Number 000, Energy series, Washington DC 77pp

5. BRONZEOAK 2001. Gemina PCN for PCF (World Bank)6. CSDA 2001. Climate Change Glossary7. INE 2001. (INE Data Base)8. Fitzgerald Kevin 2000. The Sensitivity of the Cost of GHG Credits to

Credit Eligibility Period, AED, in PCF web page9. Roberts Sarah 2001. PCF Approaches to Additionality, Baselines,

Validation and Verification, PCF training July 2001, in PCF web page.

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Annex 1 Nicaragua Background

(A1.1) General information Nicaragua is located in Central America, between Honduras and Costa Rica, 13°N, 85°W. The total surface area is 130,374 km2, of which 120,340 km2 is land and 10,034 km2 is bodies of water. Extensive Atlantic coastal plains cover almost half of Nicaragua, rising to central, interior mountains (500-1500 m above sea level) and the narrow Pacific coast plain which is interrupted by volcanoes.

Nicaragua can be divided into 4 different climatic zones using the Koppen Climate Classification (cited by MARENA 2000):

Tropical rain forest in the southeast of the Atlantic coast with average precipitation more than 4000 mm and average temperatures between 25-29ºC

Monzonic climate is in the Caribbean zone with a wet season of 9-10 months (2000-3000 mm precipitation) and average temperature of 27ºC.

Tropical savannah in the Pacific region, with a dry season of 6 months, precipitation of 700-2000 mm and an average temperature between 25-29ºC.

Sub tropical mountain climate in the North and central zones, with average precipitation of more than 1000 mm, and average temperatures between 10-25ºC.

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(A1.2) Political background

Following the overthrow of the Somoza regime, Nicaragua was ruled from 1979 to 1985 by a junta drawn from the FSLN; (Frente Sandinista de Liberación Nacional). Executive and legislative authority was centred in the Government of National Reconstruction, which received legislative advice from a Council of State. Presidential and legislative elections were held in 1984, and a new administration, still largely dominated by the FSLN, replaced the junta government in 1985. In 1990 Nicaragua became a new democratic country, ending 11 years of Sandinista rule. Three presidential elections have been carried out. The most recent president was elected on November 5th, 2001. The new government began on January 5, 2002. Improved rules to enhance private sector activity are expected.

(A1.3) Economic background Nicaragua has a developing market economy based largely on agriculture, light industries, and trade. The gross national product (GNP) had a positive real growth rate from the mid-1990s largely because of relative political and economic stability. The GNP grew in 2000 by 5.5 % and it is expected to grow by 5.2% annually to 2010. The GNP per capita is low compared to other Central American countries. Agriculture accounts for about one-fourth of the GNP but employs as much as two-fifths of the work force. Corn (maize), sorghum, and beans are the chief crops for local consumption and are harvested twice a year. Coffee, cotton, bananas, and sugar are produced primarily for export. Nicaragua's known mineral resources include large reserves of gold, copper and silver. Significant quantities of gold and silver are produced in eastern Nicaragua.

Industry - mostly processing domestic raw materials - accounts for one-fifth of the GNP and employs about one-tenth of the work force. Products include refined sugar, petroleum products, chemicals, cigarettes, leather goods, textiles, cement and plastics. The majority (70%) of Nicaragua's electricity is generated from imported fuels and the remainder from hydroelectric and geothermal sources. Nicaragua's principal exports include coffee, cotton, beef, bananas and gold. Imports consist of primary and intermediate goods for industry, mineral fuels, capital goods for industry, and transport equipment. Canada, Germany, the former Soviet Union, Cuba, USA and Japan are its main trading partners.

(A1.4) Social background

More than three quarters of Nicaragua's people are Mestizos, a racial mixture of Europeans (mostly Spanish) and American Indians. Of the original American Indian population, the Sumo, Miskito (Mosquito), and Rama peoples occupy the basins of the northeastern rivers and other areas along the Caribbean Sea. The west coast has a small number of Monimbo and Subtiaba Indian peoples. Black Creoles live in the Caribbean

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lowland. Spanish is the official language, but there is widespread familiarity with English. Nearly 90% of the population is Roman Catholic. Nicaragua has a young population; almost half its people are under 15 years of age. The birth rate is one of the highest in Central America, while the death rate is only slightly above average and declining. Since the 1950s there has also been a considerable decline in the relatively high rate of infant mortality. The country has one of the highest estimated annual rates of population growth in Central and Latin America.Health services were vastly improved under the Sandinista government after decades of neglect. However, diseases such as enteritis, tuberculosis, tetanus, and typhoid fever, however, are still common. There is a shortage of trained medical personnel, and health-care facilities are poorly equipped. Average life expectancy is about 61 years for males and 63 years for females.

Education is free and compulsory between the ages of 6 and 13 years. About three-quarters of school-age children attend primary school, but only a small percentage advance to secondary school. Nicaragua has several daily newspapers, including La Prensa, one of the largest. There are two major television stations and numerous radio stations.

Unemployment and poverty alleviation in rural areas are the most important problems for the new government.

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Annex 2 Background to the Electrical Sector in Nicaragua

(A2.1) Interconnected Grid An interconnected grid serves the west coastal and central northern areas of Nicaragua. A single transmission line connects the grid to a small area of the east coast. Other areas of the country have isolated systems.

(A2.2) Past and Current Generation & Consumption According to the study document, ‘The Electricity Sector Indicative Plan’ (CNE 2001) the electrification rate in Nicaragua, over the last twenty years has been low. The percentage of the population that can receive electricity has only risen from 45% in 1980 to 47% in 1999. By comparison Costa Rica has at least 90% of its population served by its electricity system.

In 1980 the number of consumers was 198,300. By 2001 the total number of consumers had grown to 429,330, a net addition of 116% over the 20 year period.

Although the per capita final consumption of electricity has traditionally been lower in Nicaragua than in other Central American countries (304.9 KWh/capita), the electricity sector in Nicaragua is being changed in its own structure and composition as a result of the privatisation and free market opening processes which started in 1996-1997. The distribution system was privatised in October 2000. Sales of the state owned generation plants are planned.

Table 1 shows that, over the ten year period 1990-1999, grid connected generating capacity increased by 64% from 371 MW in 1990 to 609 MW in 1999. Of this 238 MW increase only 15.8 MW, the cogeneration plant at Nicaragua Sugar ISA (a large sugar mill), was non oil fuelled plant. Except for the GT at Las Brisas, which burns diesel oil, the new oil fuelled plants used HFO. In addition, all the isolated system capacity increases were diesel generation sets, using diesel oil.

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Table 1. Nominal capacity of electrical generation units in Nicaragua.

Plants Power system Units 1990 1999Public owner MW Rated MW EffectiveNicaragua Steam, HFO 2 x 50 100.00 100.00Managua Steam, HFO 1 x 45,

2x 6 75.00 57.50

Central America Hydro power 2 x 25 50.00 50.00Santa Barbara Hydro power 2 x 25 50.00 50.00Wabule Hydro power 1 x 1.6 1.62 1.62Canoas Hydro power 1 x 1.8 1.79 1.79Las Brisas GT, Diesel oil 1x 25,1x36 0 66.00Chinandega GT, Diesel oil 1 x 15 15.00 15.00Ormat Momotombo Geothermal power 2 x 35 70.00 70.00Private ownersCensa Amfels IC, HFO 1 x 35 36.00Corinto IC, HFO 1 x 70 70.00Tipitapa IC, HFO 1 x 56.7 52.20Nicaragua Sugar ISA Co-gen., Bagasse 1 x 19.6 15.80Timal (Victorias) Co-gen., Bagasse 1 x 10 12.00Isolated systemsPublic interest Diesel oil power 10-21 units 7.80 10.37Private interest Diesel oil power 1 x 0.88 0.88TOTAL 371.21 609.15Source: INE 1999 annual report

According to the Nicaraguan Energy Institute (INE) annual report 1999, over the period 1995 to 1999, electricity generation has increased by 23.5%, from 1700 GWh in 1995 to 2100 GWh in 1999.

In addition to generating for its own use, Nicaragua also imports and exports electricity with Costa Rica, Panama and Honduras. Imports have risen from 63 GWh in 1995 to 80.3 GWh in 1999 and exports have dropped from 77 GWh to 23 GWh in 1999. This suggests a slow trend towards increased net import of electricity.

Gross generation by plant type during the period 95-99, is shown in Table 2.

In 1995 sources of electricity were 57% from fossil fuel with the balance from from renewables (hydro and geothermal). By 1999, reliance on fossil fired generation had almost increased to 73% of the total. At the same time, renewable energy’s share decreased from 717 GWh (41% of the total) to 550 GWh (26% of the total).

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Table 2 Electricity Gross Generation by type of plant during 1995-1999 (GWh)

Type of Plants Fuel Type 1995 1996 1997 1998 1999

Thermal (steam) fossil fuelNicaragua Fuel Oil 680.44 729.01 624.95 717.99 590.01Managua Fuel Oil 220.39 361.45 339.94 385.85 238.95Internal CombustiónCensa (IC) Fuel Oil 0.0 120.78 213.90 166.39Corinto (IC) Fuel Oil 0.0 129.74Tipitapa (IC) Fuel Oil 0.0 282.75Gas TurbinesChinandega Diesel Oil 22.75 2.17 17.50 39.48 18.98Las Brisas Diesel Oil 65.76 21.28 73.62 260.98 124.89Thermal(steam) biomassISA (St Antonio) Bagasse 0.0 30.80 35.88Timal (Victorias) Bagasse 0.0 29.44 29.32 28.20 19.01Hydroelectric (4) 406.91 430.71 407.14 295.56 393.26Geothermal (1) 309.55 276.50 208.75 120.53 102.14Isolated Sys. (2) Diesel Oil 21.50 13.46 14.22 17.23 21.45TOTALS: 1727.31 1864.02 1836.22 2110.52 2123.47

Source: Gross generation by type of plant (www.ine.gob.ni)

During 1999 the billed electricity consumption was 1.5 thousand GWh. The balance of 0.6 thousand GWh, almost 30% of generation is accounted for by transmission and distribution losses plus, presumably, unbilled consumption. The total consumption by consumer group was: 31% for residential customers, 23% for industrial sector, 22% for commerce and services, 10.5% for pumping water and 13.5% for public sector and illumination public service. A total of 464,214 customers were supplied by INE of which 429,334 were connected to the main system. The balance was connected to isolated systems.

(A2.3) Organization & Institutional Framework Since 1992 the organization and institutional framework of the energy sector was established by the Electricity Industry Law, LIE, (decreed Law Nº 272) or Law for the modernization Electricity sector. According to the LIE the principal institutions are:

The National Institute for Energy, INE:, This is an autonomous institution for regulatory activities, supervision and fiscal control of the energy sector and especially for the electricity market. Particularly, to approve and control tariffs, supervision of the electricity Bronzeoak



services, in terms of quality and security, elaboration of the norms and regulations, issuance the licenses, permits and concessions for generation, transmission and distribution activities.

The National Commission for Energy, CNE, is an inter-institutional panel charged with formulating sector policies and strategies, indicative planning and other directives of the sector, include rural electrification. Based on its work it makes appropriate proposals to the executive branch of government.

The Dispatch Load Centre, CNDC, is the technical manager of the electricity interconnected system (SIN). CNDC is an operational unit for ENTRESA, the national entity which retains ownership of the transmission system.

Over recent years, the electricity sector in Nicaragua has been prepared for deregulation and privatisation. The process is now well advanced. Several privately owned generators supply electricity under PPAs. A wholesale market for electricity sales is functioning with about 20% of supply traded on a day to day basis. Since October 2000, the distribution system has been privately owned and operated. The remaining step, to sell off state owned generating assets, should have been completed in 2001, but when bids were requested none that the Government found acceptable were received.

The regulatory framework developed from Law 272 and its regulations (decree 42 98) is defined in a series of seven volumes of regulations called “Normativas”. Individual volumes cover: Operation, Transport, Tariffs, Concessions and Licenses, Electricity Services, Quality of Service, Penalties and Sanctions. Together, Law 272 and the regulations define the reorganized electricity sector (generation, transmission and distribution) including: the installation of new power plants, the obligations and responsibilities of the transmission system, the rights of "Large" consumers, the conditions of the distribution and commercial activities, the duties and obligations for concessionaires and final clients, the operation of the interconnected system, the rural electrification fund, the tariff regimes etc.

In 2000, the existing distribution system was divided geographically into two parts and ownership transferred to new companies. The new companies, Disnorte and Dissur, were privatised and are currently both owned by Union Fenosa.

(A2.4) Transmission & Distribution Economic Agents, including ENTRESA, that provide transmission cannot buy or sell electricity. Economic Agents that own generators and Large consumers (consumers whose demand is at least 2 MW) are permitted to buy wholesale electricity.

Economic Agents focused in distribution activities can enter into contracts, to buy and sell electricity, with Generators (companies that are licensed to generate and sell

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electricity) and Large Consumers, they can also buy power in the spot market or in the international market. Owners of distribution systems are obligated to provide a connection line to Generators or Large Consumers, subject to defined commercial and technical provisions.

(A2.5) Electricity Market Under the Nicaraguan regulations Large Consumers who are connected at a voltage equal or more than 13.8 KV and have a load of at least 2000 kW can buy wholesale electricity. They can do this by contracting with generators or by purchasing on the spot market.

The average price for a retail consumer in 1995 was 9.0 UScents/kWh while in 1999 it was 10.5 UScents/kWh. In 2001 prices in the wholesale spot market were in the range 3.5 to 6.5 UScents/kWh for energy and 150-180US$/MW-day for capacity.

The electricity market began to function officially in October 2000. In March 2001, Union Fenosa announced that it would launch an auction to buy under contract, a total of 20 MW capacity and energy.

(A2.6) Ownership of Power Plant Currently, generator plants belong to private companies and to state owned companies.

The three largest private generation companies are :- Corinto: ENRON company USA,- Tipitapa Power: Coastal Pacific company USA,- CENSA: AMFELS company, (Korea),

In 1999 the stated owned plants were transferred to four new companies in preparation for sale to the private sector27.

Hydro-power plants were transferred to HIDROGESA. The geothermal power plant at Momotombo was transfer to GEMOSA. The Chinandega GT and the Nicaragua fuel oil fired plants were transferred to GEOSA, and the Las Brisas GT and Managua plants were transferred to GEGSA. An attempt to sell these companies in the first half of 2001 was unsuccessful. GEMOSA remains a stated owned plant but it is currently leased and operated by ORMAT SA company, (Israel). ORMAT has an agreement with Nicaragua to evaluate and implement capacity expansion of geothermal plant at Momotombo.

(A2.7) Deregulation process

27 The hydro and thermal plants were offered for sale in the first half of 2001 but no acceptable offers were received.

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The deregulation process launched in 1998 with the privatisation of ENEL has continued during 2001. For that reason, the government has created UREL (Re-structured Electric Sector Unit) to negotiate the sale of the state owned generating companies. The plan is understood that GEMOSA will continue to be leased by ORMAT, GEOSA, GECSA, and HYDROGESA will be sold. The government has announced that the sales may be possible by early 2002. Some potential buyers have been mentioned:. Hydro Quebec, AES, Keppels, Enron, Coastal, Amfels. The deregulation process has encouraged market transparency. CNDC publishes, on the internet, indicators in the wholesale market: prices, quantities and demand.

(A2.8) Energy Policy and Strategy INE has emphasized the importance of the concepts, embodied in Law 272, as the principal guidelines for the energy (including the electrical) sector:

Ensure the market operation and the self-sufficiency of energy supply Improve the private sector participation Strengthen Institutional framework Diversification of primary sources of energy Promotes the competitiveness of different technologies Promotes the intensive use of renewable energy sources

Recently, in 2000 a policy paper for Rural electrification has been launched by CNE which promotes rural electrification projects through the FODIEN fund. By these guidelines and implemented regulatory framework, as well as by statements from directors of INE and CNE, it is clear that new renewable energy projects must be commercially competitive with other energy options in the market place.

a) To work in electrical industry activities, the economic qualified agents, whatever national or international, must have a licence or concession allocated by INE. CNE would be charged to dictate the policy and to formulate the objectives, strategies and general directives of the sector. The regulation, supervision and fiscal issues of all activities in the electrical industry will be controlled by INE. The environment impacts derived from electrical industry activities will be monitored and controlled by INE and MARENA.

b) Imports of machinery, equipment, materials for generation, transmission, distribution and commercialisation of the electricity supply for the public service, will be free of duty. This includes fuel for electricity generation.

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c) The technical and commercial operation of the State Interconnected Grid (SIN) is the responsibility of the Load Dispatch National Centre (CNDC) which is part of ENTRESA.

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Density(kg/l)

Carbon% by wt.

Conversion factor


Annex 3 Carbon Dioxide Emissions from Nicaraguan Power Plants

Determination method;

First, determine the specific CO2 content of the fuel used:

x x =

Where: Conversion factor is the kg mol of CO2 relative to kg mol C.

Second, obtain specific generation for the power plant. If in kWh/USgal, convert to kWh/litre by dividing by 3.785 (litre/USgal)

Then divide the specific CO2 content of the fuel by the specific generation to obtain the CO2 emission factor:

/ =

Nicaragua 1:HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4% (Kemps Engineering Handbook)Specific Generation = 3.567kWh/l (Table 5)

0.96 x 85.4% x 44/12 = 3.00608 kg CO2/l

3.00608 / 3.567 = 0.843 kg CO2/kWh

Managua 3:HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4% (Kemps Engineering Handbook)Specific Generation = 3.514kWh/l (Table 5 – 13.3 kWh/USgal)

0.96 x 85.4% x 44/12 = 3.00608 kg CO2/l

3.00608 / 3.514 = 0.855 kg CO2/kWh Managua 4 & 5:

CO2

(kg/l)

CO2

(kg/l)Specific

Generation(kWh/l)

CO2 emission factor

(kg CO2/kW h)

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HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4% (Kemps Engineering Handbook)Specific Generation = 3.963kWh/l (Table 5 – 15.0 kWh/USgal)

0.96 x 85.4% x 44/12 = 3.00608 kg CO2/l

3.00608 / 3.963 = 0.759 kg CO2/kWh

Tipitapa:HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4% (Kemps Engineering Handbook)Specific Generation = 4.412kWh/l (Table 5 – 16.7 kWh/USgal)

0.96 x 85.4% x 44/12 = 3.00608 kg CO2/l

3.00608 / 4.412 = 0.681 kg CO2/kWh

Corinto:HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4 (Kemps EngineeringHandbook)Specific Generation = 4.62kWh/l (Table 5 – 17.5 kWh/USgal) [note: I rechecked the source ad found that Corinto is 17.5 kWh/USgal not 15.6 kWh/USgal as in latest Table 5. This will also change CO2 estimate for 2013 to 2023]

0.96 x 85.4 % x 44/12 = 3.00608 kg CO2/l

3.00608 / 4.62 = 0.657 kg CO2/kWh

CENSA:HFODensity = 0.96 (Kemps Engineering Handbook)Carbon % = 85.4% (Kemps Engineering Handbook)Specific Generation = 4.12 kWh/l (Table 5 –15.6 kWh/USgal)

0.96 x 85.4% x 44/12 = 3.00608 kg CO2/l

3.00608 / 4.12 = 0.729 kg CO2/kWh Chinandega:

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Diesel OilDensity = 0.83 (Kemps Engineering Handbook)Carbon % = 86.1% (Kemps EngineeringHandbook)Specific Generation = 2.30 kWh/l (Table 5 – 8.7 kWh/USgal)

0.83 x 86.1% x 44/12 = 2.62031 kg CO2/l

2.62031 / 2.30 = 1.139 kg CO2/kWh

Las Brisas:Diesel oilDensity = 0.83 (Kemps Engineering Handbook)Carbon % = 86.1% (Kemps EngineeringHandbook)Specific Generation = 3.30 kWh/l (Table 5 – 12.5 kWh/USgal)0.83 x 86.1% x 44/12 = 2.62031 kg CO2/l2.62031 / 3.30 = 0.794 kg CO2/kWh

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