pre-feasibility analysis of biomass fuelled cogeneration

107555.00 ● Final Report ● September 2010

Pre-Feasibility Analysis of Biomass Fuelled Cogeneration Unit for Port Hope Simpson

Final Report

ISO 9001

Registered Company

Prepared by: Prepared for:

Newfoundland and Labrador Forestry Training Association

CBCL Limited Contents i

Contents

Executive Summary ............................................................................................................................ 1

CHAPTER 1 Introduction .............................................................................................................. 4

CHAPTER 2 Port Hope Simpson Load ............................................................................................ 5

2.1 Electrical Loads ................................................................................................................... 5

2.2 Thermal Loads ..................................................................................................................... 6

CHAPTER 3 Potential Plant Sites – Preferred Site and Layout ......................................................... 9

CHAPTER 4 Fuel Availability and Costs ........................................................................................ 11

4.1 Biomass Combustion Technologies .................................................................................. 12

CHAPTER 5 Talbott BG100 .......................................................................................................... 14

5.1 Current Model................................................................................................................... 14

5.2 Next Generation Model .................................................................................................... 16

5.3 Other Talbott’s Models ..................................................................................................... 17

CHAPTER 6 Other Available Technologies ................................................................................... 18

6.1 Grate Combustion ............................................................................................................. 18

6.2 Fluidized Bed Combustion ................................................................................................ 19

6.3 Gasification ....................................................................................................................... 20

6.4 External Brayton Cycle ...................................................................................................... 22

6.5 Ericsson Cycle .................................................................................................................... 22

6.6 Technology Summary ....................................................................................................... 23

CHAPTER 7 Financial Analysis ..................................................................................................... 24

7.1 Capital Costs ...................................................................................................................... 24

7.2 Operating Costs................................................................................................................. 25

7.2.1 Regulatory Review ................................................................................................ 25

7.3 Incentives Available .......................................................................................................... 26

7.3.1 Green Energy Incentive Programs ........................................................................ 26

7.4 Sensitivity Analysis ............................................................................................................ 27

7.5 Ownership Models ............................................................................................................ 28

7.5.1 Private for Profit ................................................................................................... 28

7.5.2 Community Based ................................................................................................. 28

7.5.3 Sawmill Industry Renewal ..................................................................................... 29

CHAPTER 8 Conclusions and Recommendations.......................................................................... 31

CBCL Limited Contents ii

Appendices

A NL Hydro Energy Purchase Information

B Wood Chipper Brochures

C Base Case Financial Analysis Spreadsheets

D Proe Power Systems Information

E Community Map

CBCL Limited Executive Summary 1

EXECUTIVE SUMMARY

The purpose of this report is to evaluate the feasibility of installing a small biomass fuelled cogeneration

system in the south-eastern Labrador town of Port Hope Simpson. Cogeneration refers to the

simultaneous production of two forms of energy, in this case electricity and hot water. Electricity in Port

Hope Simpson is currently provided by Newfoundland and Labrador Hydro (NL) by using diesel

generators. This is very expensive power to produce and is sold to the retail consumer at a considerable

subsidy. NL Hydro has a policy that allows them to purchase electricity from third party generators in

non-interconnected areas.

The rate they will pay is a function of NL Hydro’s cost of production and is based on a “Share the

Savings” principle. Appendix A includes this policy document. The maximum price NL Hydro will pay for

purchased electricity under this policy is 90% of their avoided equivalent fuel cost which is determined

annually based on their average fuel cost for the year. For 2009, NL Hydro’s equivalent fuel cost in Port

Hope Simpson was $0.22/kWh. The maximum possible price they would pay for electricity from the new

cogeneration system is therefore $0.198/kWh.

Biomass cogeneration is a well established technology that is widely used in industrial applications such

as pulp and paper mills and sawmills where an abundant and cheap source of biomass is available as a

by-product of mill operations. Other areas where biomass cogeneration is sometimes feasible are

remote areas that have adequate fibre resources and expensive imported fuel such as Labrador. The

benefits of using locally harvested wood biomass for electrical and thermal energy production are

numerous.

The local economy benefits by providing jobs in the construction, operation and maintenance of the

biomass cogeneration systems. The money stays in the local economy;

Will provide employment in the forestry sector for harvesting, processing and transporting the

biomass; and

Local energy costs are less dependent on world prices for fossil fuels.

This report looks at the technical concepts of a cogeneration plant as well as a preliminary business

model.


The proposed cogeneration concept would see a biomass fired combustion system as produced by

Talbott’s Biomass Generators of Stafford U.K. The Talbott’s system is based on a modified external

Brayton cycle that uses compressed fresh air as the energy production medium. The Brayton cycle has

been in existence for over a century and is a proven concept. While efficiencies are generally lower than

for internal combustion cycles, this disadvantage is usually overcome due to flexibility and lower cost of

the fuel. An advantage of this system over a more standard biomass fired boiler and steam turbine

system is that air is considered a non lethal gas and this type of plant does not require full time operator

supervision according to the NL Boiler, Pressure Vessel, and Compressed Gas Regulations (see Section

7.2.1).

While Talbott’s have had commercial units in service for more than three (3) years, they are currently

revising the design of the BG 100, the unit proposed for Port Hope Simpson, to address some

operational problems. They are currently working on development of a smaller 25 kW and a larger 250

kW unit and don’t expect to be in production of the new BG 100 for over a year. During our meetings

with Talbott’s it was agreed that a unit should not be installed in a remote community like Port Hope

Simpson until commercial versions of the new BG 100 have been in service successfully for at least one

year, pushing back the earliest in service date to most likely late 2012 or 2013.

Capital and operating cost estimates were developed with the assistance of Talbott’s personnel based

on their projected pricing and the operational cost data from existing BG 100 installations.

With the only potential source of sawmill residue as a fuel source for the cogeneration plant out of

business, the fuel supply for the plant was assumed to be provided by local firewood suppliers at their

regular retail price of $75 - $100 per cord. The community lacks a commercial wood chipper required to

process the fuel to the uniform chip size required for use in the plant. The capital and operating costs of

this equipment adds further to the fuel cost.

Thermal customers for the 200 kWt of hot water heat from the plant are assumed to be the current

health clinic and the school since both use hot water heating systems and are the closest large heating

loads to the preferred plant site. The new school is also adjacent to the plant site and may become a

future thermal customer.

Financial analysis was performed using two potential ownership models; a community owned not for

profit model and a privately owned for profit model. Based upon a discount rate of 10%, we determined

net present value for the project over a twenty (20) year horizon. Analysis shows that the community

owned model yields a slightly positive NPV while the privately owned model is negative.

We performed sensitivity analysis around the following parameters:

Capital cost

Fuel Price

Electricity Rate

Thermal Rate

Debt/Equity ratio


Discount Rate

Interest Rate

The analysis shows the most sensitivity to discount and interest rates. This suggests that the community

owned model is most likely more feasible since shareholders in a community owned model are more

likely to accept a lower rate of return in exchange for community benefits than shareholders in a private

company that may have no connection to the community.

Table 1: Capital Cost Summary – Community Owned Cogeneration

100 KW COGENERATION PLANT CAPITAL COST SUMMARY

BG 100 Unit (including Start-Up and Training) $775,000

Powerplant Building $50,000

Fuel Storage Building $20,000

BG 100 Freight – U.K. - PHS $20,000

Site Clearing, Grading $10,000

Direct Buried Heating Pipes (2” and 4” dia.) $300,000

New 3 Phase Pole Line and Connecting Equipment $100,000

Wood Chipper $35,000

Heating Pumps, Heat Exchangers $10,000

Subtotal $1,320,000

Engineering and Project Management $80,000

Contingency $118,000

TOTAL $1,518,000

Table 2: Summary of Financial Results – Community Owned

FINANCIAL SUMMARY

Annual Electricity Exported 0.8 106 kWh

Annual Hot Water Exported 1 106 kWt

Annual Fuel Imported 1000 Ton (25% mc)

Total Investment 1,518 k CDN

Initial Equity (20%) 303 k CDN

Net Present Value 75 k CDN

As can be seen from the financial summary, the community owned model is marginally feasible. Strong

community support, a willingness to accept lower rates of return, eligibility for low interest loans and

capital grants, and a resurgence of the sawmill industry producing a low cost fuel supply could result in

the project being quite feasible.

CBCL Limited Introduction 4

CHAPTER 1 INTRODUCTION

This study will present a preliminary feasibility assessment for the development of a small scale biomass

fuelled combined heat and power plant in Port Hope Simpson, Newfoundland and Labrador. This study

is funded by the Newfoundland and Labrador Forestry Training Association and the Department of

Natural Resources in cooperation with the Southeast Aurora Development Association.

The study is in response to a proposal received by the Southeast Aurora Development Association from

Evergreen Energy Corporation of St. Thomas, Ontario to develop biomass fired combined heat and

power plants at several of the isolated communities in south-eastern Labrador using locally procured

biomass fuel processed into wood pellets. This study will consider only the feasibility of installing one

plant in Port Hope Simpson.

The study is based on the use of the Talbott’s BG100 combined heat and power unit as manufactured by

Talbott’s energy systems of Stafford, U.K. Capital and operating cost information was obtained from

Talbott’s for the BG100 and from other suppliers or other sources for balance of plant. The analysis

assumes that the plant will be fuelled with locally procured and processed chipped wood biomass and

that the plant will sell all its electrical output to NL Hydro based upon an agreed rate (see Appendix A).

Thermal energy output from the plant is assumed to be piped to two buildings, the health clinic and D.C.

Young School. The rate paid for this thermal energy is assumed to be 10% below the corresponding cost

of oil heat. Based upon discussions with personnel at Talbott’s, annual operating hours for the plant are

assumed to be 8,000 and it is assumed that the plant will have thermal load customers for an equivalent

of 5,000 hours per year.

Financial analysis of the project considered capital and operating costs, debt to equity rates, interest

rate, inflation rate, discount rate, tax rate, fuel price, electricity rate, and thermal energy rate. Based on

a twenty (20) year project life, the analysis determined the net present value of the project. Sensitivity

analyses were performed around the key variables and compared the impact on NPV.

CBCL Limited Port Hope Simpson Load 5

CHAPTER 2 PORT HOPE SIMPSON LOAD

2.1 Electrical Loads

The town electrical grid is isolated from the main Labrador interconnected grid and is supplied by a

single plant composed of 3 x 450 kW diesel fired gensets. Generation voltage is 600V, 3 phase and the

main distribution voltage is 12.5 kV, 3 phase. Maximum winter peak in 2000 was just over 700 kW and

total 2009 production was just over 3200 MWh. Plant capacity factor was approximately 40% for 2009.

The following table shows plant operating statistics for 2009.

Table 3: Port Hope Simpson 2009 Statistics

STATISTICS FOR LATEST FULL CALENDAR YEAR: 2009

System Data

System: Port Hope Simpson

Installed Capacity: 1,365 kW

Firm Capacity: 910 kW

Number of Customers: 230

Gross Peak: 701 kW

Gross Energy: 3,220,437 kWh

Fuel Consumed: 938,191 litres

Fuel Cost (consumed) $708,111

Average Plant Efficiency: 3.43 kWh/l

Average Fuel Cost: $0.755 per litre

Average Operating Cost (fuel only): $0.220 per kWh

System load growth is forecast each year for the next five (5) years. Based upon this load growth, NL

Hydro is currently forecasting the need to add an additional unit at the generating station by 2014. This

requirement will be triggered when the expected peak load exceeds the combined output of two (2) of

the existing three (3) generating units. Incorporation of the Talbott’s BG100 or a similar generation

source into the Port Hope Simpson grid could result in the investment in a fourth unit by NL Hydro being

deferred. Table 4 shows the expected system load growth in Port Hope Simpson.


Table 4: Expected System Load Growth in Port Hope Simpson

PORT HOPE SIMPSON 2009 2010 2011 2012 2013 2014 2015

Gross Peak (kW) 813 850 876 893 908 923 938

Net Peak (kW) 777 814 840 857 872 887 902

Gross Energy (MWh) 3,252 3,401 3,579 3,651 3,711 3,772 3832

Net Energy (MWh) 3,034 3,183 3,350 3,417 3,474 3,531 3587

TOTAL SALES (MWh) 2,920 3,063 3,224 3,289 3,343 3,398 3452

2.2 Thermal Loads

Most buildings in Port Hope Simpson are heated by oil, wood, or a combination of the two. Major

buildings in the town that were examined as potential thermal loads for the new plant were as follows:

Table 5: Potential Thermal Loads

BUILDING APPROXIMATE FLOOR AREA ESTIMATED ANNUAL FUEL USE

Health Centre 2,000 ft2 25,000 L

Alexis Hotel 15,000 ft2 kW

Town Hall 7,000 ft2

DC Young School 14,000 ft2 30,000 L

New School 20,000 ft2 kWh

The Health Centre has a floor area of approximately 2,000 square feet and uses an oil fired hydronic

heating system. Annual oil consumption is approximately 25,000 litres. An expansion to the current

facility is planned and the facility is adjacent to the site of the new school as well as other potential

developments such as a new interpretive centre.

Figure 1: Health Centre


The D.C. Young School is a K – 12 facility with a current student enrolment of approximately 75. The

school includes approximately nine (9) classroom/instruction rooms plus a gymnasium/auditorium. Total

floor area is estimated to be 14,000 square feet. It uses two oil fired hydronic heating boilers located in

separate parts of the building. Annual oil consumption was reported to be 30,000 litres.

Figure 2: D.C. Young School

The Alexis Hotel is located on the riverbank in the centre of town. It has thirty-six (36) guestrooms plus

dining and meeting rooms. Total floor area is estimated at 15,000 square feet. It utilizes an oil fired

hydronic heating system but oil consumption records were unavailable.

The Town Hall utilizes an oil and wood combination hydronic heating system. Total floor area is

estimated to be 7000 square feet. Annual fuel consumption was unavailable but it was reported that

heating is primarily from wood and that annual oil consumption is very low.

Figure 3: Town Hall

The new school will be replacing the current D.C. Young School when it opens later this year. The new

school is reported to be designed with an infloor hydronic heating system and oil fired boilers. The


estimated floor area of the new school is 20,000 square feet. If the new plant installation is delayed until

after the new school is completed, it will likely be the preferred thermal load, along with either the

health centre or the current school if it continues to be used and heated.

Figure 4: New School

Assuming a maximum heat output from the BG100 of 200 kWt and a heating season of approximately

5,000 hours in Port Hope Simpson, the potential thermal load to be supplied by the plant is 1,000,000

kWht.

Assuming a heat content in fuel oil of 36,000 Btu/L and a heating system efficiency of 82%, 1,000,000

kWht of hydronic heat could displace approximately 78,000 litres of fuel oil. This is less than the

combined estimated heating load of the health centre and the current school. It is recommended that

these would be the preferred thermal loads for the new plant and the new school, once in service,

should be considered as a potential load as well. The plant may not be able to displace 100% of the oil

consumption of all three buildings but it would reduce the heating costs of each building considerably.

CBCL Limited Potential Plant Sites – Preferred Site and Layout 9

CHAPTER 3 POTENTIAL PLANT SITES – PREFERRED SITE AND LAYOUT

In order to maximize potential revenue from the new plant, it must be located on a site within a

reasonable distance from existing or potential thermal loads where hot water produced by the plant can

be piped and sold. Installation costs for supply and return hot water piping to thermal loads is quite high

due to the excavation costs in rocky terrain and insulation requirements on the piping. Increased piping

distance also increases the pumping power required to convey the heating fluid and the heat losses

through the pipe wall. Larger thermal utilities generally consider 400 meters to be the maximum

economic pipe run length to connect a new thermal customer. The estimated maximum lengths for this

smaller plant will depend somewhat on the final installed cost of the piping but is likely to be no more

than 250 meters. Potential thermal customers must already utilize a hydronic heating system in order to

reduce conversion and connection costs. Although individual residences could ultimately be connected

to the plant’s heating loop, we restricted our review to larger buildings with consistent heating loads.

The buildings considered were as follows:

.1 Alexis Hotel

.2 Town Hall

.3 D.C. Young School

.4 Community Clinic

.5 New School (under construction)

A meeting was held on March 29th, 2010, to discuss potential plant sites. Sites close to either the hotel

or town hall were eliminated due to proximity of nearby residences, concerns about noise, and lack of a

sufficiently large lot nearby. There was general consensus that the best site would be in a new area

planned for future institutional development adjacent to the new school building site and within

reasonable distance of the existing school and health clinic. Additional development planned for this

area includes an expanded health clinic and a new interpretive centre. The site is further away from

existing residences than other potential sites and is sufficiently large to allow for both powerplant and

chip storage buildings as well as space for round wood storage and a wood chipper. The potential fuel

providers in the local area also have sufficient space at their properties to produce woodchips there and

deliver to the new plant if concerns about woodchipper noise becomes an issue.

CBCL Limited Potential Plant Sites – Preferred Site and Layout 10

Site development costs could be lessened somewhat by taking advantage of equipment on the site of

the new school project if the development proceeds while the school construction project is under way.

Sites near the existing powerplant were dismissed due to the absence of nearby thermal loads. Without

a thermal load, the economic viability of a plant is much more difficult.

In order to avoid the cost of the hot water piping from the plant to the thermal loads, an alternative

arrangement could involve the use of multiple small cogeneration plants installed adjacent to each

thermal load. This is possible but the difficulty is trying to match the thermal output of the unit to the

buildings thermal output. A combined heat and power (CHP) unit is designed to operate at constant

output, not a variable output like a building heating unit. The CHP unit would need some means to reject

its produced heat when the building is not calling for heat. Larger units with multiple thermal loads and

a thermal piping distribution system are better able to average the thermal load and avoid dumping

excess heat during the heating season. All CHP plants require a heat dumping system if they are to

operate year round. Operating costs are also higher with multiple smaller plants due to duplication of

maintenance and routine operational requirements. Noise and emissions from the plants can also be an

issue if located adjacent to a building in a residential area.

CBCL Limited Fuel Availability and Costs 11

CHAPTER 4 FUEL AVAILABILITY AND COSTS

There are currently three (3) active forest products companies in Port Hope Simpson. The total current

crown land fibre allocation available to the town is 20,000m³ per year but this is not currently being fully

utilized. The current forest products suppliers are:

S and N Wood Products

Strugnell’s Woodworks

Melvin Penney

Each company has facilities to produce rough lumber, dressed lumber, pulpwood, and firewood.

S and N Wood Products is the largest facility but is currently not operating. Strugnell’s Woodworks and

Melvin Penney are operating their small facilities at a low rate at present due to very low demand for

lumber in the local area. Their main product line at present is firewood sold to customers in southern

Labrador. Their current fibre allocations are as follows:

Strugnell’s Woodworks - 1,000m³/year

Melvin Penney - 1,400m³/year

Due to very low demand for lumber, there is currently very little or no mechanized wood harvesting

happening in the Port Hope Simpson area. Mechanized harvesters are still in the area, along with

trained operators, but with no demand for wood other than firewood, most harvesting is occurring

using chainsaws. Rates provided for seasoned firewood ranged from $75 to $100 per cord. Firewood air

dried for one (1) year is expected to have an average moisture content of 25%. The vast majority of the

firewood cut in the Port Hope Simpson area is black spruce which has a density of approximately 45

lbs/ft³ at 25% moisture content. A standard cord is defined as a stack of wood measuring eight (8) feet

by four (4) feet by four (4) feet high. Allowing for air spaces between the wood, the total amount of

wood fibre in a standard cord of black spruce in Port Hope Simpson is estimated at 90 ft³. This equates

to a weight of 4,050lbs/cord. At $100 per cord this yields a firewood cost of $49.40 per ton. In order to be

combusted in the Talbott’s BG100 or a similar combustion appliance, the firewood will have to be

chipped to ensure a maximum chip size of 2”. The cost to chip and deliver the fuel to the plant site is

estimated to add $10 per ton to the fuel cost, thus yielding an expected fuel cost of $59.40 per ton. The

expected fuel consumption of the BG100 based on the unit operating at full capacity for 8,000 hours per


year is 1,000 tons. This total equates to approximately 1,200m³ of wood fibre which is approximately

50% of what is currently being utilized but less than 7% of the allowable utilization of 20,000m³/year.

Discussions with each of the forest products suppliers in Port Hope Simpson indicated that supplying this

amount of additional fibre would not be a problem. Each of them have stockpiles of logs that have been

air drying for several months which could provide sufficient start-up fuel for the plant for several

months.

The current amount of sawmill residue available is so low it was not considered in the determination of

fuel availability and price. The sawmill at S and N Wood Products, if it was in full production would be

able to supply a significant portion of the fuel requirements of a single BG100 unit just from residual

material left over from sawmilling operations, mostly sawdust and slabs. It is unclear at present when

the mill will reopen since the market for locally produced lumber in Labrador is very low at present.

Some residual material at the closed facility was observed, including a large sawdust pile which could

potentially be used as fuel if it could be dried sufficiently (<25% MC).This residual material could likely

be procured for a lower price than the firewood price. The NL Hydro policy on energy purchases for

remote grids (see Appendix A) sets the energy purchase price at the midpoint between their avoided

fuel cost and the new plant’s cost of production. If the price of available biomass fuel dropped

significantly due to the reopening of the sawmill, the electricity price paid by NL Hydro would also drop,

thus reducing the incentive offered by lower fuel prices. The sensitivity analysis in the financial section

of this report shows the impact of fuel price on the feasibility of the project.

4.1 Biomass Combustion Technologies

Production of electrical and thermal energy from biomass fuel sources has been a commonly used

method of power generation for many years. Various technologies exist that allow for the conversion of

biomass fuel into electrical and thermal energy. Some technologies will be more feasible than others

based on the amount of energy needed, the available energy price, the type of available fuel, and the

location of the energy plant. In this section we will briefly describe the main energy producing

technologies that are examined in this study.

The most common form of solid biomass fuelled energy generation system utilizes a combustion

appliance to heat water in a boiler to produce high pressure steam to drive a turbine to produce

electricity. Different combustion appliances can be utilized depending upon the nature of the biomass

fuel. The turbine discharge is condensed back to water and recycled. Thermal energy can be produced

from waste heat downstream of the boiler or from steam or condensate downstream of the turbine.

These systems typically offer high rates of conversion efficiency from potential energy in the fuel to

usable energy. Due to the high pressures and temperatures generated in these systems, plants using

these technologies have high operating costs due to the need for continuous staffing supervision while

the plant is operating.

Biomass gasification systems usually involve the heating or partial combustion of the fuel. This process

gasifies most of the volatile compounds in the biomass and is composed primarily of hydrogen, carbon


monoxide, and methane. This gas, after some filtering and refinements, can be used as a substitute for

natural gas or propane in an engine, combustion turbine, or other fossil fuelled combustion appliance.

Since steam is not part of the cycle, most gasification systems don’t require full time staffing supervision

which greatly reduces the operating costs. Most systems offer high rates of conversion efficiency similar

to or higher than steam turbine systems. System complexities and costs have generally prevented the

adoption of this technology for smaller plants (<1MW) and plant capacity factors are not generally as

high as steam turbine plants.

Compressed air systems use air as the working fluid. They can work with either internal or external

combustion engines. For an internal combustion engine, the fuel must be either gas or liquid for

injection into the combustion chamber so biomass would first have to be gasified which would add to

the cost and complexity of the system. Solid biomass fuel works best in an external combustion engine.

The fuel is combusted in an appliance and the products of combustion travel through a shell and tube

heat exchanger where heat is transferred to clean compressed air in the tubes. This hot compressed air

is then expanded across a turbine or piston to produce mechanical work which is then used to produce

electricity. Waste heat exiting the heat exchanger can then be passed through a water heating boiler to

produce hot water for space heating. The only pressure components are the tubes in the heat exchanger

and no steam is produced so full time supervision is not required, thus lowering the operating costs.

Conversion efficiencies are typically not as high as steam turbine or gasification systems but reliability is

high and capacity factors of over 90%, similar to steam turbine plants, are typical.

CBCL Limited Talbott BG100 14

CHAPTER 5 TALBOTT BG100

A site visit to the Talbott’s production and test facility in Stafford, U.K. was conducted on April 12, 2010.

The visit also included a visit to a commercial installation of a BG100 at a nearby gardening centre and

discussions with engineering staff about new product developments.

5.1 Current Model

Figure 5: BG100 Diagram


Figure 6: Fuel Feed System

The Talbott’s BG100 is a biomass fuelled combined heat and power plant that is rated for an electrical

output of 100 kW and a thermal output of 200 kW.

Chipped or pelletized biomass fuel is automatically auger fed into a step grate combustor with an

automatic de-ashing system.

Figure 7: Combustion Chamber


The products of combustion then go through a triple pass ceramic lined combustion zone to ensure

complete combustion and high efficiency. They then pass through a shell and tube heat exchanger

where heat is transferred to clean compressed air in the tubes. The products of combustion exit the air

heater to a hot water boiler that produces 200 kWt of hot water at up to 90°C.

The prime mover for the BG100 is an indirect fired microturbine. Clean outside air is drawn in and

compressed in the compressor stage of the turbine to approximately 4 bar (58 psig). The air then passes

through the above mentioned heat exchanger where its temperature is increased to over 500°C. The

heated air is then expanded and cooled across the power turbine stage of the microturbine, which

powers the compressor as well as the 100 kW generator. Exhaust from this turbine is used to dry and

preheat the biomass fuel.

Figure 8: Microturbine on BG100

5.2 Next Generation Model

During discussions with Talbott personnel on April 12, 2010, it was revealed that the current BG100

model has had a number of operational problems that have necessitated a redesign of equipment. The

next generation model is still under development and was not expected to be in production until late

2010. Subsequent to the site visit, correspondence received from Talbott’s indicates that system

procurement delays have led them to decide to move forward with development of their BG25 and

BG250 models first, further delaying availability of the BG100 into 2011 or 2012.

The reasons for suspending production of the current BG100 were listed as follows:


A build-up of fly ash on the exterior of the tubes in the air heater was reducing the heat transfer

capability and ultimately, the power output of the microturbine. The next generation unit will

include a multi core cyclonic fly ash removal system.

The microturbine was a variant of an aeronautical turbine and proved to be difficult and expensive

to maintain. The next generation unit will utilize components from the turbo charging system of a

Cummins diesel engine which is expected to be more durable and less expensive to maintain.

Maintenance experience with diesel engine components is also expected to be more easily

accessible in Labrador.

The existing control system was difficult and expensive to upgrade. The next generation unit will

utilize Allen Bradley controls components which are less expensive and easier to maintain and

upgrade.

The existing unit configuration was intended to fit into two standard shipping containers. This size

limitation results in insufficient heat transfer surface area being available and an inability of the unit

to achieve its rated outputs most of the time. The next generation unit will be larger and not suffer

from this limitation.

The capital cost quoted by Talbott’s was for a next generation unit once production resumes.

5.3 Other Talbott’s Models

Talbott’s are also developing two other combined heat and power units. The BG 25 has an electrical

output of 25 kW and thermal output of 50 kW. The BG 250 electrical output of 250 kW and thermal

output of 500 kW. The BG 25 would be suitable for providing the thermal energy needs for a single large

building, such as the school. The BG 250 is capable of supplying the thermal load of most of the large

buildings in the town. Due to the distances involved to thermally connect all these buildings, it is unlikely

that this would be practical. A shorter thermal loop would then need to have a mix of public buildings

and private residences to consume the produced energy. While possible, this would increase the

administrative complexity and maintenance costs for a system with potentially fifteen (15) to twenty

(20) customers instead of one (1) to three(3). Additional concerns about the BG 250 have to do with the

electrical output. The plant is designed to operate at constant output and cannot be throttled. The

community’s electrical load during overnight hours can potentially go below 250 kW. If this condition

existed it could potentially lead to damage to the distribution grid and to customer’s property. NL Hydro

would be required to install additional safety systems to prevent this condition and would charge the

project for the initial and ongoing operating costs of these systems. NL Hydro may be likely to object to

having such a high percentage of its total grid capacity as a non dispatchable generating source.

CBCL Limited Other Available Technologies 18

CHAPTER 6 OTHER AVAILABLE TECHNOLOGIES

Other technologies are available that can provide equivalent energy output to the Talbott’s system.

Some of these typical technologies are presented below.

6.1 Grate Combustion

Grate combustion is the traditional technology used for burning solid fuels. Grates are widely used for

large power boilers found in pulp and paper mills as well as smaller heating boiler applications. Grates

are less tolerant to fuel quality variations than fluidised bed combustion systems. Fuel moisture typically

is limited to a maximum of 57% due to the ability of the furnace to maintain stable combustion. Grate

technology is relatively simple and is competitive on small scale applications.

With grate systems the wood biomass is fed into the furnace where it is burned on the furnace floor.

Combustion air is introduced under the grate and over the grate to promote complete combustion of

the fuel and minimize emissions. The hot combustion gases then pass through a boiler to create hot

water or steam. In the cogeneration application, the product produced is steam which is passed over a

steam turbine to generate electricity before being condensed in a heat exchanger to produce hot water

for space heating. This is a very common technology that is well proven with many equipment suppliers

such as KMW, Viessman, and Ideal Boilers. Scalability down to the size of the BG 100 is less common and

operating costs are relatively high for smaller output systems due to provincial regulatory requirements

for full time operators for steam plants operating at pressures above 15 psig which any steam turbine

plant does.


Figure 9: Grate Fired Boiler

6.2 Fluidized Bed Combustion

Fluidized bed combustion technologies have been used for many decades. The wood biomass is thrown

into the furnace in a similar method as a grate system also but the gas and particle velocities in the

furnace cause the fuel to be burned in suspension. The FBC is more tolerant of varying fuel qualities and

can burn mixtures from wet bark to dry sawdust and shavings. As with a grate combustion system, the

hot products of combustion leave the furnace section of the boiler and pass through heat exchangers

where the products of combustion are cooled and hot water or steam is produced. As with the grate

combustion system, cogeneration applications of this technology are common but not in the size range

of the BG 100 and operating costs are high due to the steam pressures involved.


Figure 10: Typical Biomass Fluidized Bed Boiler

6.3 Gasification

Gasification is a process in which biomass is used to produce a gaseous fuel that can then be used as a

fuel directly for power production for example in a gas turbine or reciprocating engine.

When biomass is heated with no oxygen or only about one-third the oxygen needed for efficient

combustion (amount of oxygen and other conditions determine if biomass gasifies or pyrolyzes), it

gasifies to a mixture of carbon monoxide and hydrogen—synthesis gas or syngas. Contaminants in the

syngas must be removed prior to use in an engine in order to extend operating cycles and prevent

engine damage.

Combustion is a function of the mixture of oxygen with the hydrocarbon fuel. Gaseous fuels mix with

oxygen more easily than liquid fuels, which in turn mix more easily than solid fuels. Syngas therefore

inherently burns more efficiently and cleanly than the solid biomass from which it was made. Biomass

gasification can thus improve the efficiency of large-scale biomass power facilities such as those for

forest industry residues. Like natural gas, syngas can also be burned in gas turbines, a more efficient

electrical generation technology than steam boilers, to which solid biomass is limited. Gasification


systems using solid fuels can be problematic if fuel entrained air cannot be successfully managed to

prevent reactor combustion. The systems can be difficult to balance and operate for extended periods

between maintenance shutdowns. They are not considered to be a good technical application in a

remote community.

Small gasification type cogeneration units fuelled with biomass are produced by several manufacturers

including Community Power Corp. of Colorado and Alfagy Ltd of Gloucestershire U.K. Outputs range

from 25KWe – 1000KWe (electrical output) and 30KWt – 2100KWt (thermal output). Prime movers are

typically internal combustion engines although combustion turbines are an option for larger sizes.

Figure 11: Typical Biomass Gasification Plant – Gussing Austria


Figure 12: Typical Gasifier – Nexterra – University of South Carolina

6.4 External Brayton Cycle

Entropic Energy Inc. of Port Coquitlam, British Columbia, produces a biomass fired cogeneration plant

operating on a modified external Brayton cycle using hot air similar to the Talbott’s technology. Clean air

is compressed then heated in a shell and tube heat exchanger using the products of combustion from

the combustion of biomass fuel. The heated compressed air is then expanded across a turbo expander

to produce sufficient energy to power the compressor and a generator. The hot flue gases, upon exiting

the air heater, then enter a boiler to produce hot water for space heating uses. The company has no

commercial units in operation yet and is still in a research and development phase.

Equipment intended for a remote community needs to be commercially proven so this company cannot

be recommended yet as an alternative technology provider for Port Hope Simpson.

6.5 Ericsson Cycle

This cycle utilizes an external heat source, such as a wood fired combustor, to heat compressed air

before the air is expanded across a piston to produce mechanical work. The heat lost during the

expansion phase is recovered and used to pre heat the compressed air and possibly to dry the incoming

fuel stream. The cycle is similar to the external Brayton cycle described earlier but uses a piston engine


instead of a turbine to produce its mechanical work. The system produced by Proe Power Systems

utilizes this cycle approach. Information on this system is included in Appendix D. There is no indication

from Proe Power Systems that this equipment has been proven commercially yet and cannot be

considered as a candidate for installation in Port Hope Simpson until sufficient commercial operating

data is available to assess its suitability.

6.6 Technology Summary

When considering energy generating technologies for remote communities the primary concern must

be operability. The technology must be robust, simple, and reliable. Steam turbine systems are well

proven and reliable, being the technology of choice for most thermal power plants in the world. The

problem with this technology is scalability and operating costs. A steam turbine powerplant producing

5MW of electrical output would generate approximately 40,000 MWh in a year and would require an

operating staff of five (5) operators to ensure full time coverage. A steam turbine powerplant of 0.5MW

would produce 4000 MWh per year but would still require 5 operators. With a high degree of fixed costs

even as the plant gets smaller there is practical lower limit to how small a freestanding steam turbine

powerplant can be and still be economically feasible. Previous studies have indicated that this level is

greater than 2MW which is much larger than the grid capacity in this community.

Gasification systems eliminate the fixed operator cost problem but suffer due to issues of complexity

and reliability. Most systems cannot achieve capacity factors above 75% which is too low for a combined

heat and powerplant that is providing the primary source of heating to buildings in a northern

community with a long heating season.

The compressed air system offers the benefit of simplicity and high reliability as well as low operating

costs. The next generation units from Talbott’s, utilizing components from diesel engines which are

common and serviceable in many parts of Labrador, promises to eliminate many of the reliability and

complexity issues that were problems with its first generation units. Although not ready for installation

in a remote community until commercially proven elsewhere first, this technology offers the best

chance of providing a practical biomass fuelled cogeneration source for remote electrical grids in

Labrador and elsewhere.

CBCL Limited Financial Analysis 24

CHAPTER 7 FINANCIAL ANALYSIS

7.1 Capital Costs

Capital cost estimate is based on a next generation Talbott’s BG100 unit installed in a custom built

building on the preferred site adjacent to the new school site in Port Hope Simpson. The price assumes

estimated distances and installation costs for thermal energy connections to the Health Clinic and school

and for a three phase pole line connection to the existing three phase grid. A 9% contingency and 6%

engineering and project management is included and 13% HST is included for the private sector

developer price but not for the tax exempt community ownership model. Costs are based on an

exchange rate of 1 GBP = $1.55 Cdn.

Table 6: Port Hope Simpson Biomass Fuelled Cogeneration Plant – Capital Cost Estimate

ITEM COST

BG 100 (including comm. and training) $775,000

Powerplant Building (12m x 7m x 8m h) $50,000

Fuel Storage Building (8m x 6m x 5m h) $20,000

BG 100 Freight – U.K. – P.H.S. $20,000

Site Clearing and Grading $10,000

Direct Buried Heating Pipes (2" and 4" dia.) $300,000

New 3 Phase Pole Line and Connection Equipment $100,000

Wood Chipper $35,000

Heating Pumps, Heat Exchangers $10,000

Subtotal $1,320,000

Engineering and Project Management $80,000

Contingency (9%) $118,000

Community Owned Total $1,518,000

HST (Private Developer) $197,340

Private Owned Total $1,715,340


7.2 Operating Costs Table 7: Operational Costs

FIXED

Operator (assume ½ time to load and run chipper, load fuel hopper, conduct routine

servicing)

$20,000

Administrative Costs (insurance, NL Hydro reports, energy billing, accounts payable,

accounts receivable, payroll)

$5,000

Maintenance Contract (oil and filter changes, air filter changes, tube cleaning) $8,000

Insurance $10,000

General Supplies $1,000

Miscellaneous $1,000

Total $45,000

VARIABLE

Fuel (1,000 tons @ $59,40) $59,400

TOTAL COSTS $104,400

7.2.1 Regulatory Review

CSA Standard B51.09 – General Requirements for Boilers, Pressure Vessels, and Pressure Piping

Proposed Talbott’s equipment utilizes fresh air operating at ≈ 4 bar pressure and 800°C.

Air is a non lethal gas so according to the requirements of Figure 1(b) (on page 30), it is considered a

registered pressure vessel in excess of 1.5 ft³ capacity and must be inspected by an authorized inspector

and receive a CRN number.

Under the NL Boiler, Pressure Vessel, and Compressed Gas Regulations air piping less than 20mm

nominal size is not considered pressure piping. Heat exchanger tubing for the Talbott BG100 is described

as 19mm nominal diameter (3/4”).

Under Section 32 of the regulations, the plant does not require registration if it is a power plant below

600 kW or a heating plant below 1800 kW which this proposed plant is.

Under Section 44 of the regulations, the stamps for pressure equipment fabricated outside Canada

must:

Comply with ASME.

Include a CRN number.

Include a NBBI number.

Be on a permanent attached plate.


7.3 Incentives Available

7.3.1 Green Energy Incentive Programs

7.3.1.1 ECOENERGY FOR RENEWABLE POWER

Provides up to $0.01/kWh incentive for ten (10) years.

Plant must be commissioned by March 31, 2011.

Project must have a total rated capacity of 1 MW or greater (10 BG100’s required).

7.3.1.2 ECOENERGY FOR ABORIGINAL AND NORTHERN COMMUNITIES

Up to $250,000 available for this project if applicant is the town or community group. Private sector

not eligible.

Project deadline is March 31, 2011. Applications are still being accepted but funding may already be

used up.

7.3.1.3 FEDERATION OF CANADIAN MUNICIPALITIES – GREEN MUNICIPAL FUND

Municipalities or municipal corporations are eligible for up to $4,000,000 in low interest loans and

$400,000 in grants for each project.

Project must involve retrofit of existing buildings to improve energy efficiency and reduce GHG

emissions.

Community energy systems have received funding under this program in the past.

7.3.1.4 SUSTAINABLE DEVELOPMENT TECHNOLOGY CANADA

Talbott’s technology is commercialized, not eligible.

Commercialization of a biomass fuel processing technology, such as pellets, may be eligible.

Unlikely based on only one CHP unit.


7.4 Sensitivity Analysis Table 8: Sensitivity Analysis Public Ownership Model

CAPITAL

COST FUEL ELECT THERMAL DEBT/EQUITY

DISC.

RATE

INT.

RATE NPV

$1,518,000 $59.40/ton $0.198/kWh $0.084/kWt 80%/20% 10% 7.5% 75,322 Base Case

10%

-54,274

-10%

204,917

-10%

134,364

10%

16,279

-10%

-83,716

-10%

-4,197

10%

154,840

70%/30%

120,723

8

200,331

6

378,101

5 203,560

9 -4,871

Table 9: Sensitivity Analysis Private Ownership Model

CAPITAL

COST FUEL ELECT THERMAL DEBT/EQUITY

DISC.

RATE

INT.

RATE NPV

$1,715,000 $59.40/ton $0.198/kWh $0.084/kWt 80%/20% 10% 7.5% -74,290 Base Case

10%

-191,422

-10%

42,841

-10%

-27,056

10%

-121,524

-10%

-201,520

-20%

-328,750

-10%

-137,905

10%

-10,675

70%/30%

-33,255

8

14,224

6

143,306

5 41,614

9 -14,6770


7.5 Ownership Models

7.5.1 Private for Profit

This model involves a private sector company or consortium investing in the land, plant, and connecting

infrastructure. This company would negotiate a power purchase agreement (PPA) with NL Hydro and

separate thermal energy sales agreements with thermal energy customers within a short distance of the

plant. The company will be responsible for system maintenance, energy billing, and back-up systems.

As a private for profit company, it would not enjoy tax exempt status on either equipment purchases or

corporate income.

Examples of private sector combined heat and power companies operating in Canada include facilities in

Charlottetown, Prince Edward Island and London, Ontario. Both of these systems are primarily thermal

energy delivery systems. System margins are thin and expansion to increase customer base is infrequent

due to high infrastructure installation costs.

Advantages of the private sector model are typically previous experience with system set-up and

operation leads to more efficient operation. Disadvantages are higher costs from taxes and usually

fewer local community benefits.

7.5.2 Community Based

This ownership model can be achieved with several different models, such as:

Community based cooperative.

Public Private Partnership.

Municipally owned utility.

The objective in each model is to operate a not for profit business to provide maximum benefits to the

local community. The public private ownership model, used successfully in North Vancouver, British

Columbia, offers the advantage of utility experience and operational expertise to prevent problems,

especially during the initial operating phase. The proposed plant and distribution system for Port Hope

Simpson is sufficiently small to make the advantage over the other models less pronounced. Availability

of funding through the Green Municipal Funds of the Federation of Canadian Municipalities will be

easier to obtain if the town is part of the ownership group. The system in North Vancouver was able to

access the Green Municipal Funds this way.

Advantages of the public sector model are lower or no taxes and easier access to public sector funding

support. Disadvantages may include less development and operational expertise and higher operating

costs.


7.5.3 Sawmill Industry Renewal

The initial terms of reference for this study included the examination of the feasibility of establishing a

biomass fuelled combined heat and power (CHP) plant in Port Hope Simpson that could utilize residual

material from the sawmill industry. Port Hope Simpson was established over 70 years ago as a logging

and sawmilling community and was dependant on the forests surrounding the town for the majority of

its economic activity for most of its history.

The worldwide decline in demand for newsprint and softwood lumber has had a significant negative

impact on the sawmill sector in Port Hope Simpson. The loss of pulpwood and sawlog markets as well as

a steep decline in the local demand for lumber has left sawmills in Port Hope Simpson either closed or

operating at extremely reduced levels. The majority of the cutting occurring in the surrounding forests

at present is for firewood. As previously mentioned, the current forestry operations to produce only

firewood is yielding no residual materials that could be used as fuel for the proposed CHP plant. Material

must therefore be harvested specifically to be used as fuel for the CHP plant and the costs associated

with this are equivalent to firewood costs and are higher than typical costs for biomass fuel when

sawmill residues are available. For this study, the firewood costs given to us were used to derive an

expected fuel cost delivered to the CHP plant of $59.40 per ton. In Nova Scotia, we found sawmills that

were selling residual materials, mostly sawdust and bark, for $15 - $20 per ton at the plant gate.

Woodchips are selling for a higher rate depending upon their moisture or bark content with rates

typically in the $30 - $50 per ton range plus delivery charges. The proposed CHP plant requires biomass

fuel with a maximum moisture content of 30% which is lower than typical sawmill sawdust and bark

residue which is usually cut from green logs and has a moisture content of 50% or higher. This material

would need to be dried or blended with dry material to produce a fuel mixture with the desired

moisture content. Planer shavings from air dried rough sawn lumber, at a moisture content of roughly

20%, are a good blending material.

The sawmilling industry in Port Hope Simpson cannot be revitalized solely based on the additional

revenue potential associated with selling of its residual material to our proposed CHP plant or additional

ones in the future. It can be part of greater diversification of the potential revenue streams from the

industry but the industry will still require a return of markets for its traditional products before it can be

renewed.

Some additional financial modelling was completed on the assumption that the sawmill industry will be

renewed to a sufficient level that it can supply the roughly 1000 tons of residual material needed to

sustain the proposed CHP plant. Delivery distances from any of the sawmills to the new CHP plant will

be small and chipping costs will be lower since a portion of the material supplied will be sawdust. We

examined the project feasibility using delivered fuel prices of 20, 30, and 40 dollars per ton which is a

considerable reduction over the proposed price based on firewood. The lower fuel prices will have an

affect on the potential electricity rate paid by NL Hydro based on their formula in Appendix A. The

expected electricity price is shown as well as the projected project NPV.


Table 10: Sawmill Residue - Public Ownership Model

FUEL PRICE ELECTRICITY RATE NPV

$20/TON $0.171/kWh $252,251

$30/TON $0.178/kWh $208,515

$40/TON $0.183/kWh $148,876

Table 11: Sawmill Residue – Private Ownership Model

FUEL PRICE ELECTRICITY RATE NPV

$20/TON $0.171/kWh $67,253

$30/TON $0.178/kWh $32,265

$40/TON $0.183/kWh $15,446

This table demonstrates that the project feasibility is definitely improved if lower priced sawmill residue

fuel is available. The additional revenue to the sawmill(s), based on 1000 tonnes of material, would be in

a range from approximately $17,000 - $37,000 per year. This amount, although relatively small, could be

an important revenue source for a small sawmill when profit margins are very thin.

CBCL Limited Conclusions and Recommendations 31

CHAPTER 8 CONCLUSIONS AND RECOMMENDATIONS

To an outside observer the concept of utilizing an abundant local resource to produce energy as an

alternative to an imported fossil fuel seems to make abundant sense. Biomass as firewood has been and

continues to be the primary heating fuel for most homes and small businesses in Port Hope Simpson and

in other small communities in southeastern Labrador. Hydronic heating systems, using oil or wood as

the primary fuel, are the typical heating systems in use for larger public and commercial buildings.

Buildings with hydronic heating systems are preferred for connection to thermal district heating systems

since building hook-ups are cheaper and simpler. In an ideal planned community, a cogeneration plant

would be located in the center of the community to minimize piping runs to supply heat to all thermal

customers. These communities would also be compact and uniform in dimension, again to allow for as

efficient as possible thermal energy distribution. Many of the small communities in SE Labrador,

however, developed as fishing communities and developed in a long strip along the waterfront initially

and gradually moving inland later with growth. Electric power plants were established later and due to

the isolation of many of the communities, had to be located near the waterfront since fuel resupply

could only be done by ship. With the waterfronts already developed before the powerplants arrived,

they tended to be located away from the developed parts of the community. This poses a challenge for

present day location of a biomass fuelled CHP Plant since the ideal location to reduce electrical

connection costs is adjacent to the current powerplants but since these plants are so remote from the

communities it is impractical to run a thermal district heating loop from there. Locating these CHP plants

closer to thermal loads is important to reducing capital costs and improving system efficiency although

problems with noise, space, and emissions can make this challenging as well.

CBCL Limited Appendices

APPENDIX A

NL Hydro Energy Purchase Information

2007/04/30

PURCHASE OF ENERGY BY NEWFOUNDLAND & LABRADOR HYDRO

IN NON-INTERCONNECTED AREAS

INFORMATION PACKAGE FOR GENERATORS

1. GENERAL

In order to reduce the cost of generating electricity in isolated areas not connected to the

main grid, Newfoundland and Labrador Hydro (Hydro) will consider proposals from

Generators offering to sell electricity that could displace Hydro's diesel generation. Hydro

operates twenty-two diesel systems serving communities along the Labrador Coast, the

Northern and Northeast Coast of the Island of Newfoundland and the South Coast of the

Island of Newfoundland. Plant capacities range from a low of 90 kW installed capacity to a

high of 4,100 kW installed capacity.

2. SUMMARY OF PURCHASE POLICY

Essential terms and conditions applicable to possible energy purchases by Hydro in non-

interconnected areas shall be set out in an agreement. The following guidelines will cover

the main issues in such agreements:

(a) Price

• The unit price (cents per kilowatt hour), which Hydro will pay for electricity will be

based on a "Share-the Savings" principle. An example of "Share-the-Savings"

principle is:

- 2 -

Generator’s cost of supply = 12.00 cents/kWh Hydro's incremental cost of Diesel generation = 16.00 cents/kWh

Difference to be shared = 4.00 cents/kWh

Share-the-Savings Price = 14.00 cents/kWh

• The upper limit on the price paid by Hydro will be 90% of Hydro's incremental

cost of diesel generation (fuel only) for the system under consideration.

• Hydro's incremental cost of diesel generation will be based on the actual

monthly average fuel consumption costs and the diesel plant’s gross

production.

• The Generator’s costs will be updated annually.

• In order to determine the purchase price each year, the Generator will be

required to provide to Hydro an annual audited statement showing details of

its cost of supply, following the rules set for financial statements by Generally

Accepted Accounting Principles (GAAP).

(b) General and Special Terms of a Purchase Agreement

• Hydro will agree to purchase all kilowatt hours made available by the

Generator to Hydro on the above pricing formula, providing that the

combination of load and minimum diesel generation required for system

purposes is sufficient to absorb the kilowatt hours offered.

- 3 -

• The Generator shall provide to Hydro utility grade electrical supply at the

point of interconnection (e.g. within acceptable utility standards for voltage

and frequency regulation).

• The Generator will be responsible for all costs of generating and delivering

(including the interconnection) electricity to the Hydro system. Any costs

incurred by Hydro in modifying its physical facilities to facilitate the purchase

of energy from the Generator will be the responsibility of the Generator. Prior

to Hydro incurring any interconnection costs, the Generator will issue to

Hydro an irrevocable line of credit for 115% of Hydro’s estimated

interconnection costs. The Generator will reimburse Hydro for its actual

interconnection costs as incurred, prior to the in-service date of the

Generator’s plant.

• The Generator will be responsible for obtaining all government approvals,

permits, and licenses and for all costs associated with these approvals,

permits or licenses.

• The Purchase Agreement will require that the Generator’s project must be

commissioned and provide reliable deliveries of energy within a specific time

frame after the Purchase Agreement has been executed. The time frame will

be set by Hydro following consultations with the Generator. Failure to

commission the project within that time frame will entitle Hydro to terminate

the Purchase Agreement.

• The Generator must comply with safety, technical and operating criteria

specified by Hydro for the interconnection and operation of the proposed

facilities in conjunction with Hydro's system. This includes the provision and

installation of all necessary equipment to protect the Generator's system from

Hydro's system and vice versa. (See Appendix I).

- 4 -

• Hydro shall have no financial or legal liability should the Generator have

problems during construction or during operation of his facilities.

• Any greenhouse gas or similar emission credits or other negotiable rights or

interests arising from environmental attributes of either the ownership or

operation of the Generator’s plant will, during but limited to the term of the

purchase agreement, be vested in Hydro.

• At the Generator’s expense, the Generator shall prepare, copy and retain any

records such as meteorological, hydrological, etc. and any operating data

pertaining to the Generator’s generating facilities and, upon Hydro’s request,

provide them to Hydro, in an electronic spreadsheet format.

• Hydro will be saved harmless from any injury or failure, which may result as a

consequence of interconnection with Hydro's system.

(c) Terms of Purchase Agreement

• In general, the term of the agreement would range from 15 to 20 years but

would be subject to any plans Hydro may have to interconnect an isolated

area to the main power grid.

(d) Early Interconnection

• If Hydro interconnects an area earlier than originally planned or supplies

service from some source of energy that is substantially less expensive than

Hydro’s diesel generating plant, the Generator may either:

- 5 -

(a) Terminate the agreement and sell its generating plant to Hydro at

its net book value at that time; or

(b) Sell energy to Hydro at a rate that is based on the “share the

savings” principle as noted above except that instead of being

based on up to a maximum of 90% of Hydro’s incremental cost of

diesel generation at Hydro’s diesel generating plant, it will be

based upon up to a maximum of 90% of Hydro’s avoided lowest

incremental cost energy source for the community at that time.

• The option for the Generator to sell his plant to Hydro would not apply if

interconnection does not occur within the term of the purchase agreement.

3. ESSENTIAL INFORMATION REQUIRED IN PROPOSALS PROVIDED

BY GENERATORS

Generators offering to sell energy to Hydro in non-interconnected areas must provide the

following information in their proposals to Hydro:

(a) A summary description of the overall proposed development including details

on major system components. The following information shall be included:

• Detailed technical engineering and operating studies.

• A map indicating the location of the project, the routing of the proposed

intertie line and location of proposed interconnection with Hydro's system.

• Power plant capacity.

• A preliminary single line diagram.

• Basic information on protection and control equipment proposed to be

installed by the Generator (e.g. type of protective relaying; relay type and

- 6 -

capacity for control equipment). Further detailed drawings and specifications

will be required if the proposal is accepted.

• Voltage at point of interconnection.

• Estimates of wind regime in an area for wind energy projects and hydrology

information for hydroelectric development proposals.

• Estimates of monthly energy deliveries to Hydro's system.

(b) The term proposed for the purchase agreement.

(c) Arrangements for operation and maintenance of the Generator's system.

(d) The Generator’s estimated cost of supply in cents/kWh.

(e) A financial plan, in spreadsheet format, covering the full agreement period

with a copy supplied in electronic format.

4. INFORMATION PACKAGE FOR A SELECTED NON-INTEGRATED AREA

Appendix II attached is a typical information package for a non-interconnected area served

by Hydro diesel generation. This information includes historical and forecast data where

applicable (e.g. loads, generation capacity, fuel costs, operating costs (fuel only)), a

location map and a one-line schematic of the diesel plant. The forecast data will be revised

by Hydro from time to time. Upon request an information package will be made available to

the Generator for the selected isolated system.

APPENDIX I

Technical Requirements and General

Terms of Interconnection with Hydro's Isolated Systems

(a) The Generator must provide and maintain electrical protection such that at all times

its system and generator(s), and Hydro's system will be protected from damage

and/or hazardous conditions related to the parallel operation of two systems. Any

relays which may be required in Hydro's facilities due to the connection of a

Generator's system will be installed at the Generator's cost by Hydro and will

become the property and responsibility of Hydro. Relays required on the

Generator's system are the Generator’s property and responsibility.

(b) Hydro will require the Generator to follow appropriate operating procedures as set

out in “The Operating Agreement”, to be developed by Hydro and signed by both

Hydro and the Generator that are not substantially different from those procedures

followed for Hydro’s own generators. Operating procedures will include provisions

for routine switching operations, for example, for scheduled maintenance or for

emergencies including forced outages and unexpected contingencies, as well as a

line of communication between Hydro and the Generator. These procedures are to

enable Hydro to interrupt the flow of electricity from the Generator. Hydro will

provide the Generator with copies of the operating procedures and these operating

procedures, and any revisions or additions, will be incorporated into the purchase

agreement.

(c) Depending on the size of the Generator’s plant, Hydro may require that its diesel

plant be fully automated before connection of the Generator’s plant to Hydro’s

system in order to control the quality of service to Hydro’s customers. The cost of

the automation would be the responsibility of the Generator.

(d) A general overview of the operating philosophy for a particular project is essentially

that the Generator’s plant will act as a slave to Hydro’s master diesel plant. The

diesel plant control provides a maximum operating set point to the Generator’s

generator/turbine controls. The Generator’s plant uses this information along with

Hydro’s operating limits for the Generator’s plant, to control the Generators plant. In

order to control this set point adequately, a dump load (thermal heat sink) may be

required (size dependant) at the Generator’s site. At the diesel plant, Hydro will

require real time information about the operating status of the Generator’s plant

such as what units are on or off, kW output, Wind speed for a wind farm site, amps

and volts at the interconnection points including power flow direction in kW and

kVAR, individual unit generator breaker status as well as information as to the status

of any capacitor banks. In order to accomplish this a dedicated and dependable

communications link will be required between Hydro’s diesel plant and the

Generator’s plant facilities. Hydro will require the technical details of exactly how this

communication link will interface with any future Modicon PLC system at Hydro’s

diesel plant, if and when it is automated. The choice of a reliable communication link

is critical, since parallel operation of the Generator’s plant with Hydro’s diesel plant

will not be permitted when this link is inoperative. With this information Hydro can

then advise as to what modifications need to be made to Hydro’s equipment and

finalize any associated costs. . The Generator will be totally responsible for the day-

to-day operation of its facility and will provide the personnel to operate and maintain

the facility.

(e) Hydro’s standard customer transformer winding configuration is a Wye grounded

primary to Wye grounded secondary connection. This type of connection does not

act as a zero sequence source and is Hydro’s preference for a Generator’s

transformer connection.

(f) The Generator will put in place the appropriate controls and mechanisms to

insure that the Power produced from the Generator’s plant does not cause the

total output from Hydro’s diesel generating plant to fall below 35%, or such higher

or lower proportion that is consistent with Good Utility Practice as Hydro may

determine, of the prime power rating of the smallest diesel generating unit that is

ready and available for operation at that time in its diesel generating facility. If

Hydro wishes to change the installed capacity in its diesel plant, it may do so at

its discretion. At such time the Generator will update its controls as appropriate

and at the Generator’s expense.

(g) At its sole discretion, Hydro may, at any time suspend, disconnect or otherwise act

to control or terminate the delivery of electricity whenever adverse supply conditions,

safety or technical problems appear.

(h) Hydro reserves the right to perform acceptance tests on a Generator's protection

and generation equipment or to request that the Generator provide third party

certification on the operation of his protection equipment. Hydro also reserves the

right to monitor from time to time the electrical characteristics of the Generator's

system. The performance or failure to perform any such tests or monitoring will not

leave Hydro responsible for any consequences of the test or the later operation of

the Generator's generation, nor shall such tests or monitoring constitute a license or

permission of any kind. Protection of the Generator's system is the Generator's

responsibility.

(i) Generators will be required to have a visible, lockable isolating switch interlocked

with the generator breaker or with load interrupting capabilities. The isolating switch

must be accessible to Hydro at all times and exterior to any building housing the

generators’ equipment or controls. This switch shall be suitable for being secured

by a standard Hydro padlock. In addition, Hydro may require that Generators

provide control equipment, which would permit remote tripping of the Generator's

generator.

(j) Generators will be required to pay for installation of an "out" meter and an "in" meter

to measure power flows to and from Hydro's system, respectively. The location of

the required meters will be designated by Hydro.

APPENDIX II Date: December 31, 2006

Statistics for Latest Full Calendar Year: 2006

SYSTEM DATA

System: Charlottetown

Installed Capacity: 2,250 kW (725 kW, 725 kW, 300 kW, 250 kW, & 250 kW)

Firm Capacity: 1,525 kW

No. of Customers: 202

Peak: 1,481 kW (Gross)

Energy: 4,812 kWh (Gross)

Avg. Plant Efficiency: 3.33 kWh/L

Avg. Fuel Cost: $0.742/L

Avg. Operating Cost (fuel only): $0.223/kWh

LOAD FORECAST - GROSS

CHARLOTTETOWN Year

Peak (kW) Energy (MWh)

2006 2007 2008 2009 2010 2011 2012 2013

1,481 1,484 1,501 1,516 1,525 1,535 1,544 1,553

4,812 5,182 5,272 5,359 5,392 5,425 5,459 5,492

APPENDIX II Date: December 31, 2006

Statistics for Latest Full Calendar Year: 2006

SYSTEM DATA

System: Cartwright

Installed Capacity: 2,189 kW (765 kW, 504 kW, 470 kW, & 450 kW)

Firm Capacity: 1,424 kW

No. of Customers: 330

Peak: 859 kW (Gross)

Energy: 3,954 kWh (Gross)

Avg. Plant Efficiency: 3.26 kWh/L

Avg. Fuel Cost: $0.731/L

Avg. Operating Cost (fuel only): $0.224/kWh

LOAD FORECAST - GROSS

CARTWRIGHT Year

Peak (kW) Energy (MWh)

2006 2007 2008 2009 2010 2011 2012 2013

859 908 920 942 956 972 986

1,002

3,954 4,248 4,385 4,490 4,558 4,634 4,703 4,780

Cartwright

Monthly Energy and Peak Demand

Year

Gross

Production

(MWh)

Peak

Demand

(kW) 2005 2006

2002 4354 962 MWh kW MWh kW

2003 4213 909 Jan 387 867 340 792

2004 4254 906 Feb 374 784 355 741

2005 4036 896 Mar 315 774 332 691

2006 3954 859 Apr 322 729 307 671

May 356 879 326 859

2007 4248 908 Jun 356 896 407 841

2008 4385 920 Jul 303 717 304 725

2009 4490 942 Aug 343 792 309 690

2010 4558 956 Sep 310 740 281 618

2011 4634 972 Oct 286 691 318 651

2012 4703 986 Nov 327 733 335 757

2013 4780 1002 Dec 357 837 340 810

File: Y:\Requests\[Cartwright & Charlottetown History & Forecast.xls]Charlottetown

Prepared by: System Planning

Date: 05/07/07

Domestic, Non-Fishery General Service, Fishery

0

500

1,000

1,500

2,000

2,500

3,000

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

MWh

Domestic

General Service

Fish Plant

Charlottetown

Monthly Energy and Peak Demand

Year

Gross

Production

(MWh)

Peak

Demand

(kW) 2005 2006

2002 5073 1389 MWh kW MWh kW

2003 4808 1421 Jan 275 671 264 635

2004 5296 1374 Feb 223 612 234 684

2005 5149 1500 Mar 229 633 238 589

2006 4814 1481 Apr 221 659 231 615

May 414 1145 229 570

2007 5182 1484 Jun 528 1349 488 1451

2008 5272 1501 Jul 823 1498 808 1481

2009 5359 1516 Aug 785 1500 769 1422

2010 5392 1525 Sep 736 1500 717 1397

2011 5425 1535 Oct 417 1281 315 1181

2012 5459 1544 Nov 230 891 233 606

2013 5492 1553 Dec 268 686 288 697

File: Y:\Requests\[Cartwright & Charlottetown History & Forecast.xls]Charlottetown

Prepared by: System Planning

Date: 05/07/07

Domestic, Non-Fishery General Service, Fishery

0

500

1,000

1,500

2,000

2,500

3,000

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

MWh

Domestic

General Service

Fish Plant

CH

AR

LO

TT

ET

OW

N L

oad D

ura

tion C

urv

e

(Based o

n N

LH

Isola

ted D

iesel S

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m typic

al data

)

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

1300

1400

1500

1600

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

PU

Tim

e

Load [kW]

CA

RT

WR

IGH

T L

oad

Du

rati

on

Cu

rve

0

10

0

20

0

30

0

40

0

50

0

60

0

70

0

80

0

90

0

10

00

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

PU

Tim

e

Gross Load [kW]

BLACK

DIESEL PLANT

ST. BRENDAN'S

LITTLE BAY ISLANDS

RAMEA

GREY RIVER

FRANCOIS McCALLUM

NAIN

HOPEDALE

POSTVILLEMAKKOVIK

RIGOLET

CARTWRIGHTTICKLE

NORMAN BAYPARADISERIVER

PORT HOPESIMPSON

CHARLOTTETOWNWILLIAMS HARBOUR

ST. LEWIS

MARY'S HARBOUR

L'ANSE AU LOUP

LABRADOR

NEWFOUNDLAND

L E G E N D

Provincial Isolated Systems (Diesel)

THE POWER OFCOMMITMENT

NATUASHISH


APPENDIX B

Wood Chipper Brochures

GENERALChipping capacity .................................................................8”Length (transport).....12’7’’ (operating) ...................... 15’Height ....................................................................................7’4’’ Width ......................................................................................5’3”Gross weight ............................................2,150 - 2,750 lbs.Suspension .................................................2,500 lb. torsionInfeed opening ......................33 1/2’’ wide x 24 1/2” highThroat opening ..................................... 12” wide x 8” highFeed wheel................................. 111/2” wide x 9” diameterDisc dimensions .......................11/4” thick x 28” diameterEngine ...............................CAT, Kubota, Perkins, or KohlerHorsepower ...............................................................27-38 HPFuel capacity (tank) ...............................................9 gallonsHydraulic oil capacity .............................................8 gallonsFrame ................................................................. 2” x 4” tubularTires .............................................................. (2) 185/80R x 14”Hitch ........................................................2” ball or 21/2” lunet

EQUIPMENT HIGHLIGHTSDirect driveAutomatic feed systemPinned chipper hood with integrated hood safety switch allows ease of disc maintenance and main-tains hood’s structural integrity Top feed wheel compression system with spring assisted down pressure2” x 4”, fully boxed tubular steel frameFolding infeed tray reduces transport length and increases maneuverabilitySwing away front jack with castor wheel

MORBARK BEEVER M8D

BENEFITS

· Top feed wheel compression system with 32.3ci hydraulic motor generates 2,612 lb/ft of pulling force.

· 28% larger top feed wheel motor than comparable models

· 33% larger capacity than comparable 6” models

· Only chipper in its class to combine both a wide infeed and thick chipper disc in one unit

· Ideal unit for: Rental yards, landscapers, golf courses, and pruning crews

S P E C I F I C A T I O N S

C H I P P E R D I S C 28” diameter x 11/4” thick chipper disc

with (4) bolt-on chip paddles.

I N F E E D C H U T EFolding infeed chute with 96 in2 throat

opening

F E E D S YS T E MTop feed wheel compression system with spring assisted down pressure

F R AM E2” x 4” tubular steel frame with 4”

square tongue.

800-831-0042 • 989-866-2381www.morbark.com

ADDITIONAL FEATURES360° manual swivel dischargeFuel and hydraulic tank sight gaugesAdjustable chip deflectorExclusive hydraulic tank inspection cover

OPTIONSVariable speed flow controlElectric brake systemBreakaway actuatorSpecial color paint2 1/2” Lunet ring

MORBARK, INC. Toll free 800-831-0042 * Phone (989) 866-2381 * Fax (989) 866-2280 * www.morbark.com

GENERALChipping capacity ...............................................................12”Length ................................................................................. 15’9”Height ....................................................................................8’5” Width ...................................................................................5’ 11”Gross weight .......................................................... 5,500 lbs.Suspension ..................................................6,000 lb. torsionInfeed Opening ....................................48” wide x 31” highThroat Opening ....................................15” wide x 12” highDrum ......................................... 141/2” wide x 20” diameterEngines ........................ CAT, Kubota, John Deere, PerkinsHorsepower ................................................ 51 HP to 115 HPFuel capacity .......................................................... 22 gallonsHydraulic oil capacity .......................................... 16 gallonsFrame ................................................................. 2” x 4” tubularTires .............................................................. (2) 225/75R x 15”Hitch .......................................................21/2” Lunet or 2” Ball

EQUIPMENT HIGHLIGHTSLive hydraulics allow use of hydraulic functions without engaging chipper drumHydra-Lift compression system with spring assisted down pressureReversing automatic feed systemFour blade integrated air-impeller system with perfo-rated drum slides2-pocket, staggered knife cutting system allows one full cut per revolution2” x 4” fully boxed, extended steel frame360° manual crank swivel dischargeDirect drive, dual feed wheel compression system with combination serrated teeth and knife bars

MORBARK BEEVER M12R

BENEFITS

· Dual feed wheel compression system generates 3,413 lb/ft of combined pulling force

· 1612 in2 infeed opening with 180 in2 throat opening

· Ideal unit for: Residential tree services, utility line clearing, rental facilities and municipalities

· Customizable to fit individual needs

S P E C I F I C A T I O N S

TO P F E E D W H E E L18” diameter top feed wheel with

combination serrated teeth and knife bars

D R I V E B E LT CO V E RDrive belt inspection cover provides ease

of drive system maintenance

HYD R A - L I F T T M S YS T E MHydra-Lift Compression System with

spring assisted down pressure

D I S C H A R G E360° Manual Crank Swivel

Discharge

800-831-0042 • 989-866-2381www.morbark.com

ADDITIONAL FEATURESAdditional 1000 lbs. of yoke down pressure at valve handleBottom feed wheel clean-out doorHydraulic tank inspection coverTelescoping tongue with (2) 12” extensions

OPTIONS Light-duty winch package Aluminum diamond plate fendersRadiator brush guardFolding infeed traySpecial color paint


APPENDIX C

Base Case Financial Analysis Spreadsheets

Earnings Statement

1 Revenue

Gross Electrical Output 100 kw

Net Electrical Power output kw 100 kw

Gross Plant Heat Rate 0 btu/kwhr

Electrical energy production @8000 hrs/yr 800,000 kWh

Rate 0.1980 $/KWHR

Annual escalation 2.00%

Thermal energy production 1,000,000 Kwht

Thermal energy rate 0.08 $/Kwht

Capacity Factor 0.00 $/mwhr

Initial availability of plant on an annual basis 100.0%

Annual degradation of power available 0.000%

6.1.3 Annual O&M Cost Estimate

(All costs in 2005 CAN$)

Operating and Maintenance - Fixed

Manager 0

Admin. Personnel 5,000

Maintenance Contract 8,000

Operator 20,000

Consultants 0

Insurance 10,000

General Supplies 1,000

Miscellaneous 1,000 -11.53%

Fuel 0

burn rate LB/HR

PRICE $/TONNE 59.40

Fuel Heating Value btu/lb 0

Tonnes/year 1,000

Total Fuel 59,400.0

Total costs - 1st year 104,442


3 Accounts receivable

Collection of revenue as follows:

Current 0.0%

30 days 100.0%

60 days 0.0%

Provision for Bad debts 0.0%

Port Hope Simpson Cogen Plant

0


100.0%

Total annual revenue - amount in A/R at end of year 8.3%

4 Capital Costs

Non depreciable 0

Depreciable 1,715,000

Total 1,715,000

Depreciation Rates - Straight line - years 10.0

Capital Additions Year Amount

-Depreciation on capital additions - Straight7 0

line 14 0

4 Financing of Capital Costs

Debt 80.0% 1,372,000

Equity / Internal 20.0% 343,000

Minimal rate of return on equity 10.0%

(Discount rate)

Financing of Capital Additions Loan #2

Debt 50.0% 0

Equity 50.0% 0

Terms of Debt

Loan #1 Loan #2

Interest Rate 7.50% 7.50%

Term - years debt to be paid 10 0

Paid in # of periods per year 4 4

Pv

Future value of debt at end of termFv 0 0

Payments at beginning (1) or end of periodType 0 0

5 Bank Operating Loan

Interest on bank debt 10.0%

6 Accounts payable

Payment of expenses under the following terms

Current 0.0%

30 days 100.0%


60 days 0.0%

100.0%

Total annual expenses, amount in A/P at end of year 8.3%

7 Corporate tax rate 20.0%

Capital Cost Allowance Rate 40.0%

Payable in 180

8 Dividends

Net minimum retained earnings: 0

- balance paid out as dividends in following year


Projected Statement of Earnings

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Revenue

Electrical energy production @8000 hrs/yr 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000

Rate 0.1980 0.2020 0.2060 0.2101 0.2143 0.2186 0.2230 0.2274 0.2320 0.2366 0.2414 0.2462 0.2511 0.2561 0.2613 0.2665 0.2718 0.2772 0.2828

Total 158,400 161,568 164,799 168,095 171,457 174,886 178,384 181,952 185,591 189,303 193,089 196,950 200,890 204,907 209,005 213,186 217,449 221,798 226,234

Secondary electrical energy production 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Rate 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Thermal energy production 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000

Rate 0.084 0.0857 0.0874 0.0891 0.0909 0.0927 0.0946 0.0965 0.0984 0.1004 0.1024 0.1044 0.1065 0.1087 0.1108 0.1131 0.1153 0.1176 0.1200

Total 84,000 85,680 87,394 89,141 90,924 92,743 94,598 96,490 98,419 100,388 102,396 104,443 106,532 108,663 110,836 113,053 115,314 117,620 119,973

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Capacity Payment 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total potential revenue 242,400 247,248 252,193 257,237 262,382 267,629 272,982 278,441 284,010 289,690 295,484 301,394 307,422 313,570 319,842 326,238 332,763 339,419 346,207

% available 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Gross revenue 242,400 247,248 252,193 257,237 262,382 267,629 272,982 278,441 284,010 289,690 295,484 301,394 307,422 313,570 319,842 326,238 332,763 339,419 346,207

Expenses

Operating and maintenance 104,442 106,531 108,661 110,835 113,051 115,312 117,619 119,971 122,370 124,818 127,314 129,860 132,458 135,107 137,809 140,565 143,376 146,244 149,169

Interest on debt 100,242 92,836 84,860 76,268 67,013 57,045 46,307 34,742 22,284 8,865 0 0 0 0 0 0 0 0 0

Depreciation and amortization 171,500 171,500 171,500 171,500 171,500 171,500 171,500 171,500 171,500 171,500 0 0 0 0 0 0 0 0 0

Amortization capital additions 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total expenses 376,184 370,867 365,021 358,602 351,565 343,857 335,426 326,213 316,154 305,183 127,314 129,860 132,458 135,107 137,809 140,565 143,376 146,244 149,169

Net Income before corporate taxes -133,784 -123,619 -112,828 -101,366 -89,183 -76,228 -62,444 -47,771 -32,144 -15,492 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Corporate taxes -26,757 -24,724 -22,566 -20,273 -17,837 -15,246 -12,489 -9,554 -6,429 -3,098 33,634 34,307 34,993 35,693 36,407 37,135 37,877 38,635 39,408

Net income -107,027 -98,895 -90,263 -81,093 -71,346 -60,982 -49,955 -38,217 -25,715 -12,394 134,536 137,227 139,971 142,771 145,626 148,539 151,509 154,540 157,630

Retained earnings - beginning -107,027 -205,922 -296,185 -377,277 -448,624 -509,606 -559,561 -597,778 -623,493 -635,887 -501,351 -364,125 -224,153 -81,383 64,243 148,539 151,509 154,540

Dividends 0 0 0 0 0 0 0 0 0 0 0 0 0 0 64,243 148,539 151,509 154,540

Retained earnings - end -107,027 -205,922 -296,185 -377,277 -448,624 -509,606 -559,561 -597,778 -623,493 -635,887 -501,351 -364,125 -224,153 -81,383 64,243 148,539 151,509 154,540 157,630


Projected Balance Sheet

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

ASSETS

Cash -69,785 -98,787 -127,012 -154,530 -181,416 -207,758 -233,649 -259,195 -284,511 -309,725 -138,732 -1,112 139,259 282,438 428,481 513,201 516,605 520,077 523,618

Accounts receivable 20,200 20,604 21,016 21,436 21,865 22,302 22,748 23,203 23,668 24,141 24,624 25,116 25,618 26,131 26,653 27,187 27,730 28,285 28,851

-49,585 -78,183 -105,996 -133,093 -159,551 -185,456 -210,901 -235,992 -260,844 -285,584 -114,108 24,004 164,878 308,569 455,134 540,387 544,335 548,362 552,469

Capital Assets

Non depreciable 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Depreciable 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000

1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000

Accumulated depreciation 171,500 343,000 514,500 686,000 857,500 1,029,000 1,200,500 1,372,000 1,543,500 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000 1,715,000

Net 1,543,500 1,372,000 1,200,500 1,029,000 857,500 686,000 514,500 343,000 171,500 0 0 0 0 0 0 0 0 0 0

Total assets 1,493,915 1,293,817 1,094,504 895,907 697,949 500,544 303,599 107,008 -89,344 -285,584 -114,108 24,004 164,878 308,569 455,134 540,387 544,335 548,362 552,469

LIABILITIES

Accounts payable 8,704 8,878 9,055 9,236 9,421 9,609 9,802 9,998 10,198 10,401 10,610 10,822 11,038 11,259 11,484 11,714 11,948 12,187 12,431

Corporate taxes -26,757 -24,724 -22,566 -20,273 -17,837 -15,246 -12,489 -9,554 -6,429 -3,098 33,634 34,307 34,993 35,693 36,407 37,135 37,877 38,635 39,408

-18,053 -15,846 -13,511 -11,037 -8,416 -5,636 -2,687 443 3,769 7,303 44,244 45,128 46,031 46,952 47,891 48,848 49,825 50,822 51,838

Long term debt 1,275,996 1,172,586 1,061,199 941,221 811,988 672,787 522,848 361,343 187,381 0 0 0 0 0 0 0 0 0 0

Total liabilities 1,257,942 1,156,740 1,047,689 930,184 803,572 667,150 520,161 361,787 191,150 7,303 44,244 45,128 46,031 46,952 47,891 48,848 49,825 50,822 51,838

EQUITY

Capital 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000 343,000

Retained earnings -107,027 -205,922 -296,185 -377,277 -448,624 -509,606 -559,561 -597,778 -623,493 -635,887 -501,351 -364,125 -224,153 -81,383 64,243 148,539 151,509 154,540 157,630

Total equity 235,973 137,078 46,815 -34,277 -105,624 -166,606 -216,561 -254,778 -280,493 -292,887 -158,351 -21,125 118,847 261,617 407,243 491,539 494,509 497,540 500,630

Total Liabilities and Equity 1,493,915 1,293,817 1,094,504 895,907 697,949 500,544 303,599 107,008 -89,344 -285,584 -114,108 24,004 164,878 308,569 455,134 540,387 544,335 548,362 552,469

Return on Investment

Earnings before tax -133,784 -123,619 -112,828 -101,366 -89,183 -76,228 -62,444 -47,771 -32,144 -15,492 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Interest on long term debt 100,242 92,836 84,860 76,268 67,013 57,045 46,307 34,742 22,284 8,865 0 0 0 0 0 0 0 0 0

Earnings before interest and tax -33,542 -30,783 -27,968 -25,098 -22,170 -19,183 -16,137 -13,030 -9,860 -6,627 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Investment - Net debt & equity 1,715,000 1,511,969 1,309,664 1,108,015 906,944 706,364 506,181 306,287 106,565 -93,112 -292,887 -158,351 -21,125 118,847 261,617 407,243 491,539 494,509 497,540

Return on Investment (ROI) before tax -1.96% -2.04% -2.14% -2.27% -2.44% -2.72% -3.19% -4.25% -9.25% 7.12% -57.42% -108.32% -828.24% 150.16% 69.58% 45.59% 38.53% 39.06% 39.60%

Return on Investment (ROI) after tax -1.56% -1.63% -1.71% -1.81% -1.96% -2.17% -2.55% -3.40% -7.40% 5.69% -45.93% -86.66% -662.60% 120.13% 55.66% 36.47% 30.82% 31.25% 31.68%

Return on equity (ROE) after tax -45.36% -41.91% -65.85% -173.22% 208.14% 57.74% 29.98% 17.65% 10.09% 4.42% -45.93% -86.66% -662.60% 120.13% 55.66% 36.47% 30.82% 31.25% 31.68%

-11.53%

Net present value of investment (NPV) -74,290

Net investment - equity 343,000

Net positive (negative) return -417,290

Total dividends paid during operation 837,244 676,461 518,831 364,291 212,782 64,243 0 0 0


Projected Statement of Cash Flow

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Cash From Operations

Net Income -107,027 -98,895 -90,263 -81,093 -71,346 -60,982 -49,955 -38,217 -25,715 -12,394 134,536 137,227 139,971 142,771 145,626 148,539 151,509 154,540 157,630


64,473 72,605 81,237 90,407 100,154 110,518 121,545 133,283 145,785 159,106 134,536 137,227 139,971 142,771 145,626 148,539 151,509 154,540 157,630

Cash From Financing

Bank loan

Accounts payable 8,704 174 178 181 185 188 192 196 200 204 208 212 216 221 225 230 234 239 244

Corporate taxes payable -26,757 2,033 2,158 2,293 2,437 2,591 2,757 2,935 3,125 3,330 36,733 673 686 700 714 728 743 758 773

Debt 1,372,000

Capital addition debt 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Capital 343,000

Total cash provided 1,696,947 2,207 2,336 2,474 2,621 2,779 2,949 3,131 3,325 3,534 36,941 885 903 921 939 958 977 997 1,016

Cash Used

Accounts receivable 20,200 404 412 420 429 437 446 455 464 473 483 492 502 512 523 533 544 555 566

Land 0

Buildings and equipment 1,715,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Debt repayment 96,004 103,410 111,386 119,978 129,233 139,201 149,939 161,505 173,962 187,381 0 0 0 0 0 0 0 0 0

Dividends 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 64,243 148,539 151,509 154,540

Total cash used 1,831,204 103,814 111,798 120,399 129,662 139,639 150,385 161,959 174,426 187,854 483 492 502 512 523 64,776 149,082 152,064 155,105

Net cash provided (used) -69,785 -29,002 -28,225 -27,518 -26,887 -26,342 -25,891 -25,546 -25,316 -25,214 170,994 137,619 140,372 143,179 146,043 84,720 3,404 3,472 3,542

Cash - beginning -69,785 -98,787 -127,012 -154,530 -181,416 -207,758 -233,649 -259,195 -284,511 -309,725 -138,732 -1,112 139,259 282,438 428,481 513,201 516,605 520,077

Cash - end -69,785 -98,787 -127,012 -154,530 -181,416 -207,758 -233,649 -259,195 -284,511 -309,725 -138,732 -1,112 139,259 282,438 428,481 513,201 516,605 520,077 523,618

Earnings Statement

1 Revenue

Gross Electrical Output 100 kw

Net Electrical Power output kw 100 kw

Gross Plant Heat Rate 0 btu/kwhr

Electrical energy production @8000 hrs/yr 800,000 kWh

Rate 0.1980 $/KWHR


Thermal energy production 1,000,000 Kwht

Thermal energy rate 0.08 $/Kwht

Capacity Factor 0.00 $/mwhr

Initial availability of plant on an annual basis 100.0%

Annual degradation of power available 0.000%

6.1.3 Annual O&M Cost Estimate

(All costs in 2005 CAN$)

Operating and Maintenance - Fixed

Manager 0

Admin. Personnel 5,000

Maintenance Contract 8,000

Operator 20,000

Consultants 0

Insurance 10,000

General Supplies 1,000

Miscellaneous 1,000 1.10%

Fuel 0

burn rate LB/HR

PRICE $/TONNE 59.40

Fuel Heating Value btu/lb 0

Tonnes/year 1,000

Total Fuel 59,400.0

Total costs - 1st year 104,442


3 Accounts receivable

Collection of revenue as follows:

Current 0.0%

30 days 100.0%

60 days 0.0%

Provision for Bad debts 0.0%


0


100.0%

Total annual revenue - amount in A/R at end of year 8.3%

4 Capital Costs

Non depreciable 0

Depreciable 1,518,000

Total 1,518,000

Depreciation Rates - Straight line - years 10.0

Capital Additions Year Amount

-Depreciation on capital additions - Straight7 0

line 14 0

4 Financing of Capital Costs

Debt 80.0% 1,214,400

Equity / Internal 20.0% 303,600

Minimal rate of return on equity 10.0%

(Discount rate)

Financing of Capital Additions Loan #2

Debt 50.0% 0

Equity 50.0% 0

Terms of Debt

Loan #1 Loan #2

Interest Rate 7.50% 7.50%

Term - years debt to be paid 10 0

Paid in # of periods per year 4 4

Pv

Future value of debt at end of termFv 0 0

Payments at beginning (1) or end of periodType 0 0

5 Bank Operating Loan

Interest on bank debt 10.0%

6 Accounts payable

Payment of expenses under the following terms

Current 0.0%

30 days 100.0%


60 days 0.0%

100.0%

Total annual expenses, amount in A/P at end of year 8.3%

7 Corporate tax rate 0.0%

Capital Cost Allowance Rate 40.0%

Payable in 180

8 Dividends

Net minimum retained earnings: 0

- balance paid out as dividends in following year


Projected Statement of Earnings

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Revenue

Electrical energy production @8000 hrs/yr 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000 800,000

Rate 0.1980 0.2020 0.2060 0.2101 0.2143 0.2186 0.2230 0.2274 0.2320 0.2366 0.2414 0.2462 0.2511 0.2561 0.2613 0.2665 0.2718 0.2772 0.2828

Total 158,400 161,568 164,799 168,095 171,457 174,886 178,384 181,952 185,591 189,303 193,089 196,950 200,890 204,907 209,005 213,186 217,449 221,798 226,234

Secondary electrical energy production 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Rate 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Thermal energy production 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000

Rate 0.084 0.0857 0.0874 0.0891 0.0909 0.0927 0.0946 0.0965 0.0984 0.1004 0.1024 0.1044 0.1065 0.1087 0.1108 0.1131 0.1153 0.1176 0.1200

Total 84,000 85,680 87,394 89,141 90,924 92,743 94,598 96,490 98,419 100,388 102,396 104,443 106,532 108,663 110,836 113,053 115,314 117,620 119,973

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Capacity Payment 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total potential revenue 242,400 247,248 252,193 257,237 262,382 267,629 272,982 278,441 284,010 289,690 295,484 301,394 307,422 313,570 319,842 326,238 332,763 339,419 346,207

% available 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Gross revenue 242,400 247,248 252,193 257,237 262,382 267,629 272,982 278,441 284,010 289,690 295,484 301,394 307,422 313,570 319,842 326,238 332,763 339,419 346,207

Expenses

Operating and maintenance 104,442 106,531 108,661 110,835 113,051 115,312 117,619 119,971 122,370 124,818 127,314 129,860 132,458 135,107 137,809 140,565 143,376 146,244 149,169

Interest on debt 88,727 82,172 75,112 67,507 59,315 50,492 40,988 30,751 19,724 7,847 0 0 0 0 0 0 0 0 0


Amortization capital additions 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total expenses 344,969 340,503 335,573 330,142 324,167 317,604 310,407 302,522 293,895 284,465 127,314 129,860 132,458 135,107 137,809 140,565 143,376 146,244 149,169

Net Income before corporate taxes -102,569 -93,255 -83,380 -72,905 -61,785 -49,975 -37,425 -24,080 -9,884 5,226 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Corporate taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Net income -102,569 -93,255 -83,380 -72,905 -61,785 -49,975 -37,425 -24,080 -9,884 5,226 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Retained earnings - beginning -102,569 -195,824 -279,205 -352,109 -413,895 -463,870 -501,295 -525,375 -535,260 -530,034 -361,864 -190,330 -15,366 163,097 182,033 185,673 189,387 193,175

Dividends 0 0 0 0 0 0 0 0 0 0 0 0 0 163,097 182,033 185,673 189,387 193,175

Retained earnings - end -102,569 -195,824 -279,205 -352,109 -413,895 -463,870 -501,295 -525,375 -535,260 -530,034 -361,864 -190,330 -15,366 163,097 182,033 185,673 189,387 193,175 197,038


Projected Balance Sheet

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

ASSETS

Cash -47,242 -80,458 -110,865 -138,406 -163,023 -184,659 -203,253 -218,745 -231,073 -240,173 -72,278 98,975 273,653 451,825 470,463 473,801 477,205 480,677 484,218

Accounts receivable 20,200 20,604 21,016 21,436 21,865 22,302 22,748 23,203 23,668 24,141 24,624 25,116 25,618 26,131 26,653 27,187 27,730 28,285 28,851

-27,042 -59,854 -89,849 -116,969 -141,158 -162,356 -180,504 -195,541 -207,405 -216,032 -47,654 124,091 299,272 477,956 497,117 500,987 504,935 508,962 513,069

Capital Assets

Non depreciable 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Depreciable 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000

1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000

Accumulated depreciation 151,800 303,600 455,400 607,200 759,000 910,800 1,062,600 1,214,400 1,366,200 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000 1,518,000

Net 1,366,200 1,214,400 1,062,600 910,800 759,000 607,200 455,400 303,600 151,800 0 0 0 0 0 0 0 0 0 0

Total assets 1,339,158 1,154,546 972,751 793,831 617,842 444,844 274,896 108,059 -55,605 -216,032 -47,654 124,091 299,272 477,956 497,117 500,987 504,935 508,962 513,069

LIABILITIES

Accounts payable 8,704 8,878 9,055 9,236 9,421 9,609 9,802 9,998 10,198 10,401 10,610 10,822 11,038 11,259 11,484 11,714 11,948 12,187 12,431

Corporate taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

8,704 8,878 9,055 9,236 9,421 9,609 9,802 9,998 10,198 10,401 10,610 10,822 11,038 11,259 11,484 11,714 11,948 12,187 12,431

Long term debt 1,129,423 1,037,892 939,301 833,104 718,716 595,504 462,789 319,836 165,857 0 0 0 0 0 0 0 0 0 0

Total liabilities 1,138,127 1,046,770 948,356 842,340 728,137 605,114 472,590 329,834 176,054 10,401 10,610 10,822 11,038 11,259 11,484 11,714 11,948 12,187 12,431

EQUITY

Capital 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600 303,600

Retained earnings -102,569 -195,824 -279,205 -352,109 -413,895 -463,870 -501,295 -525,375 -535,260 -530,034 -361,864 -190,330 -15,366 163,097 182,033 185,673 189,387 193,175 197,038

Total equity 201,031 107,776 24,395 -48,509 -110,295 -160,270 -197,695 -221,775 -231,660 -226,434 -58,264 113,270 288,234 466,697 485,633 489,273 492,987 496,775 500,638

Total Liabilities and Equity 1,339,158 1,154,546 972,751 793,831 617,842 444,844 274,896 108,059 -55,605 -216,032 -47,654 124,091 299,272 477,956 497,117 500,987 504,935 508,962 513,069

Return on Investment

Earnings before tax -102,569 -93,255 -83,380 -72,905 -61,785 -49,975 -37,425 -24,080 -9,884 5,226 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Interest on long term debt 88,727 82,172 75,112 67,507 59,315 50,492 40,988 30,751 19,724 7,847 0 0 0 0 0 0 0 0 0

Earnings before interest and tax -13,842 -11,083 -8,268 -5,398 -2,470 517 3,563 6,670 9,840 13,073 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Investment - Net debt & equity 1,518,000 1,330,454 1,145,668 963,696 784,595 608,421 435,235 265,094 98,061 -65,803 -226,434 -58,264 113,270 288,234 466,697 485,633 489,273 492,987 496,775

Return on Investment (ROI) before tax -0.91% -0.83% -0.72% -0.56% -0.31% 0.08% 0.82% 2.52% 10.03% -19.87% -74.27% -294.41% 154.47% 61.92% 39.00% 38.23% 38.71% 39.18% 39.66%

Return on Investment (ROI) after tax -0.91% -0.83% -0.72% -0.56% -0.31% 0.08% 0.82% 2.52% 10.03% -19.87% -74.27% -294.41% 154.47% 61.92% 39.00% 38.23% 38.71% 39.18% 39.66%

Return on equity (ROE) after tax -51.02% -46.39% -77.36% -298.85% 127.37% 45.31% 23.35% 12.18% 4.46% -2.26% -74.27% -294.41% 154.47% 61.92% 39.00% 38.23% 38.71% 39.18% 39.66%

1.10%

Net present value of investment (NPV) 75,322

Net investment - equity 303,600

Net positive (negative) return -228,278

Total dividends paid during operation 1,311,381 1,110,402 913,364 720,190 530,803 345,130 163,097 0 0


Projected Statement of Cash Flow

Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Cash From Operations

Net Income -102,569 -93,255 -83,380 -72,905 -61,785 -49,975 -37,425 -24,080 -9,884 5,226 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038


49,231 58,545 68,420 78,895 90,015 101,825 114,375 127,720 141,916 157,026 168,170 171,533 174,964 178,463 182,033 185,673 189,387 193,175 197,038

Cash From Financing

Bank loan

Accounts payable 8,704 174 178 181 185 188 192 196 200 204 208 212 216 221 225 230 234 239 244

Corporate taxes payable 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Debt 1,214,400

Capital addition debt 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Capital 303,600

Total cash provided 1,526,704 174 178 181 185 188 192 196 200 204 208 212 216 221 225 230 234 239 244

Cash Used

Accounts receivable 20,200 404 412 420 429 437 446 455 464 473 483 492 502 512 523 533 544 555 566

Land 0

Buildings and equipment 1,518,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Debt repayment 84,977 91,531 98,592 106,197 114,388 123,212 132,716 142,953 153,979 165,857 0 0 0 0 0 0 0 0 0

Dividends 0 0 0 0 0 0 0 0 0 0 0 0 0 0 163,097 182,033 185,673 189,387 193,175

Total cash used 1,623,177 91,935 99,004 106,617 114,817 123,649 133,162 143,408 154,444 166,330 483 492 502 512 163,620 182,566 186,217 189,941 193,740

Net cash provided (used) -47,242 -33,216 -30,407 -27,541 -24,617 -21,636 -18,594 -15,492 -12,328 -9,100 167,895 171,253 174,678 178,172 18,638 3,337 3,404 3,472 3,542

Cash - beginning -47,242 -80,458 -110,865 -138,406 -163,023 -184,659 -203,253 -218,745 -231,073 -240,173 -72,278 98,975 273,653 451,825 470,463 473,801 477,205 480,677

Cash - end -47,242 -80,458 -110,865 -138,406 -163,023 -184,659 -203,253 -218,745 -231,073 -240,173 -72,278 98,975 273,653 451,825 470,463 473,801 477,205 480,677 484,218


APPENDIX D

Proe Power Systems Information

PPS250

Combined Heat and Power System

Electricity Production:

- 250 kW - 2,125,000 kWh per annum

Thermal Production:

- 300 kWt - 1,054,000 BTUs

Purchase Price:

- Project specific Operational hours annually:

- 8,568 hours

Biomass Feed Stocks: - Wood chips - Energy Crops - Agri waste fibers - Others to be determined

Bio-fuel:

- 1,170 tonnes annually - 140 kg or 308 lb per hour

PPS250 Powerplant

Cost of Generating Electric Power10 Year Payback - Wood or Grass Fuel

($60) ($40) ($20) $0 $20 $40 $60 $80 $100

Cost of Fuel (US$/Tonne)

$0.000

$0.010

$0.020

$0.030

$0.040

$0.050

$0.060

$0.070

$0.080

$0.090

Co

st o

f E

lectr

ic P

ow

er

(US

$/k

W-h

r)

Purchased FuelsWaste Fuels

EverGreen Energy Corp

2-89 Chestnut Street 519-631-6035 St. Thomas, ON N5R 2B1 [email protected]

mailto:[email protected]

Proe Power Systems PPS250 Biofuel Powerplant

Performance/Unit:

Electric Power Output: 250 kW minimum with 20°C Dry Air

Available Waste Heat: 90 to 300 kWt (Depending on Fuel Drying Required) 2000 to 6500 lph of 60°C Hot Water

Electrical Efficiency: >32% Thermal Efficiency: >36% (Includes Fuel Drying) >68%

Availability: 8568 hr/yr

Limited Warranty (First Units):

Proe Power Systems, LLC warrants that the Powerplants will perform substantially in accordance with

the above performance level for a period of one (1) year from the date of installation and that the

Powerplants will be free from defects in materials and workmanship under normal use and service for

a period of six (6) months.

Warranty (After Test Verification):

Proe Power Systems, LLC warrants that the Powerplants will perform in accordance with the above

performance level for a period of three (3) years from the date of installation and that the Powerplants

will be free from defects in materials and workmanship under normal use and service for a period of

one (1) year.

Operation:

Starting:

The PPS 250 Biofuel Powerplant is started by putting dry fuel onto the combustor fire grate and

igniting it with lighter fluid or commercial fire starting sticks. A start blower is turned on to provide air

to the fire and the combustor doors are closed to seal the combustor.

The fire heats the air heater and, when the heater reaches operating temperature, the engine is

turned over with a starter motor and begins to run. The start blower is then turned off and isolated by

closing a start air valve. Then Powerplant is then operating normally.

Fuel Feed:

Wet solid fuel is automatically conveyed from the fuel storage hopper to the dryer feed hopper. It then

passes through the fuel dryer where it is dried by the engine exhaust. Except with very wet fuel, the

dryer will remove almost all the fuel moisture. The dry fuel is then conveyed to the combustor fuel

feed and automatically fed to the combustor by air-tight airlocks and augers. After combustion, the

ash is automatically removed from the combustor through a similar auger and air lock.

Powerplant control:

Powerplant control consists of matching the power output to the load demand while also maintaining

the proper air/fuel mixtures. Ideally, the Powerplant operates at the design power rating. However,

when load demand falls, the engine power is reduced to match by controlling the air into the engine

compressors. Fuel flow is then adjusted accordingly by controlling the fuel feed conveyors and

augers. With multiple Powerplants, load adjustment can also be made by taking some individual units

off-line so that the remaining units can continue to operate, at peak efficiency, at the rated power.

Maintenance:

In normal operation the Powerplant only requires a steady supply of fuel (wet or dry) and periodic

removal of ash from the ash collection bins. Soot is automatically swept from the air heater by

commercially available boiler soot blasters. The frequency of operation of the soot blasters depends

on the ash content of the fuel.

Long term periodic maintenance consists of meeting the mechanical maintenance demands of the

engine (changing filters and lubricants etc.) and cleaning the fuel and ash paths. The air heater is

designed with provisions so it can be brushed and swept of ashes, annually or semiannually. The fuel

feed system should be cleaned of fuel residue (such as sawdust) periodically to assure the fuel

airlocks and augurs seal effectively and all the mechanical parts are free to move.


APPENDIX E

Community Map

© All Rights Reserved. Jan 2009. Slide 1

Presented by

www.ACCcogeneration.ca | [email protected]

BIOMASS 2 ENERGY (B2E)

A Sustainable and Clean Solution with a Value-Based Business Case

that delivers Combined Heat & Energy for

Remote, Aboriginal Communities.


Presented by


Aboriginal Cogeneration Corporation (ACC)Is an Aboriginal owned company that services partners such as Aboriginal Communities, Aboriginal Businesses, Railways, Forestry and the Agricultural sector for the effective disposal of scrap railway ties and other wood based waste biomass in an environmentally safe manner.

Our MissionTo develop value-based business partnering opportunities with communities and companies as the core focus of ACC’s business activities

To encourage Economic Development opportunities for Aboriginal people

To create sustainable and affordable power/heat generation facilities, based on a unique Microgasification technology operated by ACC

To transition Fossil fuel energy production to Biomass energy


Presented by


Focus on Aboriginal Off Grid communities

Reduce Greenhouse gases by reducing diesel generated power through fuel switching programs

Create meaningful employment

Selective forestry, waste reduction

Sustainable way of life

We Have the Human Resources


Presented by


We Have the Natural Resources

Create Capacity to manage forests and agricultural lands.

Enhances their capacity to participate in forest-based and farming businesses.

Increase Aboriginal cooperation and partnerships, and investigate mechanisms for financing.


Presented by


Why Biomass Energy?

High Green House Gas (GHG) Displacement Potential*

*Information obtained from report entitled “Assessment of GHG Emission Reduction Alternatives”


Presented by


Pyrolysis or Devolatilization ZoneThermo chemical conversion of fuel to gaseous by-products and char

Oxidation ZonePartial oxidation of pyrolysis by-products to maintain exothermic heat profile and tar cracking

Reduction Zone Reduction reaction between unconverted char and combustion products CO2 and H2O

ACC Downdraft

Microgasification Process


Presented by


Commercially ViableGasification Systems


Presented by


Combined Heat and Power System for Greenhouses or Industrial facilities

Existing Diesel Generator Modified for Syngas


Presented by


800 KWt Engine

Jacket Heat Recovery

1250 KWe to Grid

1250 KWt Engine Exhaust Heat Recovery

5000 KWt from Syngas

Total Energy Balance (1.5t/hr of wood)

Total Energy

3300 KWt


Presented by


Measured Emissions from the Gas Engine Generator Stack

Measured Value

(25 kWe)

1-MWe Engine

Generator(projected value in

ton/years)

US EPA Permitted

Values

Emission Species

mg/m3

gram/hp-

hourgram/hp-

hourSO2 3 0.02 0.147 –CO 572 3.48 32.047 4NOx 100 0.61 5.580 2HC 3.24 0.02 0.181 1TPM 1.4 0.01 0.078


Presented by


Solid Residue5.5%–8% of inorganic material which is recovered as solid residue or ash.

3%–5% unconverted carbon (or char) removed from the bottom of the gasifier as residue.

Meets TCLP levels, non hazardous and can be disposed of on the ground without undergoing any processing.

WastewaterThe process water used during operations will mainly be re-circulated within the system and any waste water will be discharged into the existing sanitary sewer system.

Effluent from operations will meet Sewer Bylaws (300mg/l COD).


Presented by


Packaged to meet the strictest environmental requirements and permits.

Inherently safe design, low pressure, meets Occupational Safety and Health Administration (OSHA) and National Electrical Code (NEC) standards, computer-monitored and logic-based feedback interface.

Completely automated to minimize operational cost. Simplified maintenance and recycled process consumables.

Can be coupled with existing natural gas or diesel engine generators that are already online to produce electrical power.

Small footprint enables use in portable applications.

OVERVIEW


Presented by


THANK YOUFor additional information please contact:

Aboriginal Cogeneration Corporation

(204) [email protected]

pre-feasibility analysis of biomass fuelled cogeneration

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