Roaring Fork Biomass Consortium · The Roaring Fork Biomass Consortium is a group of non-profit...

Roaring Fork Biomass Consortium

S m a l l - S c a l e B i o m a s s T e c h n o l o g y R e v i e w

Final Project Report September 2011

Roaring Fork Biomass Consortium

S m a l l S c a l e B i o m a s s T e c h n o l o g y R e v i e w

Final Project Report September 2011

Table of Contents

Page CHAPTER 1 – EXECUTIVE SUMMARY..................................................................................1

1.1 Technology Assessment Results ..................................................................................1 1.2 Economic Results .........................................................................................................5

1.2.1 Power Only......................................................................................................................... 5 1.2.2 Heat and Power ................................................................................................................. 5 1.2.3 Heat Only ........................................................................................................................... 5

1.3 Recommendations ........................................................................................................6

CHAPTER 2 – PROJECT BACKGROUND .............................................................................7

CHAPTER 3 – BIOMASS UTILIZATION TECHNOLOGIES........................................................9 3.1 Descriptive Overview of Biomass Technologies ...........................................................9

3.1.1 Biomass Gasification ....................................................................................................... 10 3.1.1.1 Technology Description.......................................................................................... 10 3.1.1.2 Commercial Status of Gasification Systems .......................................................... 11

3.1.2 Direct Combustion............................................................................................................ 12 3.1.2.1 Technology Description.......................................................................................... 12

3.1.3 Commercial Status of Direct Combustion Systems ......................................................... 13 3.1.4 Anaerobic Digestion......................................................................................................... 13

3.2 Biomass and Air Quality..............................................................................................15 3.2.1 Carbon ............................................................................................................................. 15 3.2.2 Other Emissions............................................................................................................... 16

3.3 Technology Comparison Matrix ..................................................................................17 4.1 Power Only..................................................................................................................18

4.1.1 Direct Combustion............................................................................................................ 18 4.1.2 Gasification ...................................................................................................................... 20 4.1.3 Other Power Market Options ........................................................................................... 21

4.2 Combined Heat and Power .........................................................................................21 4.2.1 Direct Combustion............................................................................................................ 21 4.2.2 Gasification ...................................................................................................................... 23

4.3 Heat Only ....................................................................................................................23 4.3.1 Direct Combustion............................................................................................................ 23 4.3.2 Gasification ...................................................................................................................... 25

APPENDIX 1

APPENDIX 2

THE BECK GROUP September, 2011 Portland, OR Page 1

CHAPTER 1 – EXECUTIVE SUMMARY

The Roaring Fork Biomass Consortium is a group of non-profit entities who aim to evaluate the biomass energy potential for the Greater Roaring Fork Valley and to educate community members on the applicability of biomass for regional heating, electricity, and fuel production. As part of those efforts, a woody biomass fuel supply study was completed by TSS Consultants in April, 2011. They found that about 5,800 to 6,600 bone dry tons of woody biomass would be sustainably available each year in the Roaring Fork Valley. That amount of fuel is relatively small, so the objectives of this report are to:

1) Assess the small-scale technologies available for converting woody biomass to heat, power, or both.

2) Provide a preliminary economic analysis of using biomass to produce heat, power, or both.

It must be noted that technology criteria such as capital costs, operating costs, emissions, etc. are all sensitive to site specific factors such as fuel quality, fuel moisture, miscellaneous site development costs, etc. Since no specific site was identified for this study, The Beck Group (BECK) has attempted to use normalized data derived from prior installations. More definitive analysis of capital and operating costs can not be produced without more specific information about the site, heat loads, fuel type, moisture content, etc.

1.1 TECHNOLOGY ASSESSMENT RESULTS Two broad technology categories were assessed: 1) direct combustion; and 2) gasification. In addition to these key technologies, 3 scenarios (heat only, heat and power, power only) in which those technologies could be applied were also studied. The following Table 1 shows selected key findings with respect to each technology and application.



Table 1 – Comparison Matrix of Biomass Conversion Technologies for Selected, Key Criteria

Direct Combustion Gasification

Criteria Heat Only Heat and

Power Power Only Heat Only Heat and

Power Power Only

Capital Cost $275,000 per MMBTU/hr

$5 to $6 million per MW


$225,000 per MMBTU



Operating Expense

$7.90 per MMBTU/hr

$184 per MW hour

$175 per MW hour

$6.90 per MMBTU/hour

> $242 per MW hour

$242 per MW hour

Energy Efficiency

55 to 75 percent

40 to 75 percent

15 to 30 percent

55 to 75 percent

*see energy efficiency paragraph below

*see energy efficiency paragraph below

Job Creation (permanent,

direct)

0 5 5 0 5 5

As shown in Table 1, in terms of capital cost, gasification appears to be slightly lower than direct combustion systems in heat only applications. There is little difference in capital costs for heat and power and power only applications.

In terms of operating costs, direct combustion is lower in heat and power and power only applications. A key reason for this finding is that direct combustion systems tend to operate more hours per year than gasification systems, especially two-stage gasification systems. As a result, the per unit operating costs are higher for gasification systems.

In contrast, for heat only applications gasification operating costs are lower. This finding is driven primarily by the slightly lower capital cost for gasification systems.

Regarding overall energy efficiency, little difference exists between direct combustion and gasification for a heat only application due to the fact that there are only a given number of BTUs per pound of fuel. The amount of heat that can be used to create steam for heating varies little by technology type.

However, when the process also includes the production of power, gasification theoretically has the potential to be more efficient. This is because the producer (or syngas) created as part of a two-stage gasification process can potentially be used to more efficiently producer power when it is combusted in a turbine or fed into an internal combustion engine. In actual practice though, the producer (syngas) contains impurities that need to be filtered or condensed out. This filtering (or cleaning process) or condensation lowers the temperature of the gas, causing the release of energy and therefore, losing much of the efficiency that could have been gained by generating power directly from the syngas as opposed to generating power using steam as the working fluid.

Numerous vendors are working on an effective way to clean the syngas without losing the "sensible heat" that could create higher efficiency by direct combustion. However,



at this time, none have been able to accomplish this goal. As a result, the efficiency of producing power today using gasification technology is in reality no more effective than using a direct combustion system.

Air quality, as affected by the emissions of biomass energy applications, is another key area of concern. Table 2 provides a comparison of emissions associated with various biomass conversion technologies with coal and natural gas technologies. The data is from a comprehensive Biopower Technical Assessment1 related to biomass energy. As shown in Table 2, biomass is low relative to coal in terms of SOx emissions, but higher in terms of CO emissions, primarily due to the moisture content of most biomass fuels. Regarding a comparison of direct combustion and gasification technologies for biomass, the table illustrates that gasification tends to have fewer emissions (except for NOx, which is slightly higher than direct combustion) and much lower levels of particulates.

1 Biopower Technical Assessment: State of the Industry and Technology. R.L. Bain and W.A. Amos, National Renewable Energy Laboratory. M. Downing and R.L. Perlack, Oak Ridge National Laboratory. March 2003. NREL. Accessed at: http://www.fs.fed.us/ccrc/topics/urban-forests/docs/Biopower_Assessment.pdf


THE BECK GROUP August 8, 2011 Portland, OR Page 4

Table 2 – Direct Air Emissions from Wood Residue Facilities by Boiler Type

SOx

(lbs. per MWh) NOx

(lbs. per MWh) CO

(lbs. per MWh) PM 10

(lbs. per MWh) Comments

Biomass

Stoker Boiler, Wood Residues (Direct Combustion)

0.08 2.1 (biomass type not specified)

12.2 (biomass type not specified)

0.50 (total particulates) (biomass type not specified)

Based on 23 CA grate boilers, except for SO2 uncontrolled.

Fluidized Bed (Direct Combustion)




0.30 (total particulates) (biomass type not specified)

Based on 11 fluidized bed boilers in CA

Energy Crops (Gasification)

0.05 1.10 to 2.2 0.66 to 1.32 w/SCNR 0.22 to 0.44 w/SCR

0.23 0.01 (total particulates)

*Combustor flue gas goes through cyclone and baghouse. Syngas goes through scrubber and baghouse before gas turbine. No controls on gas turbine.

Coal

Bituminous Coal Stoker Boiler

20.2 (1 wt% S coal)

5.8 2.7 0.62 PM Control Only (baghouse)

Pulverized Coal Boiler

14.3 6.89 0.35 0.32 (total particulates)

Average US PC boiler (typically baghouse, limestone FGC)

Co-firing 15 percent Biomass

12.2 6.17 0.35 0.32 (total particulates)

Fluidized Bed, Coal 3.7 (1wt % S coal Ca/S = 2.5)

2.7 9.6 0.30 Baghouse for PM Control, Ca sorbents used for SOx

Natural Gas

4-Stroke NG Reciprocating Engine

0.006 7.96 to 38.3 (depends on load and air:fuel ratio)

2.98 to 35.0 (depends on load and air:fuel ratio)

0.09 to 0.18 (depends on load and air:fuel ratio)

No control except PCC at high-end of PM-10 range

Natural Gas Turbine (g)

0.009 (0.0007 wt % S)

1.72 0.4 0.09 (total particulates)

Water-Steam injection only

Natural Gas Combined Cycle

0.004 0.91 (0.21 w/SCR)

0.06 0.14 (total particulates)

Water-Steam injection only

*Note that the figures for gasification are based on theoretical calculations rather than actual measurements



1.2 ECONOMIC RESULTS BECK also performed a high level economic assessment of gasification and direct combustion technology in three applications: heat only, heat and power, and power only. The results are evaluated in the following paragraphs.

1.2.1 Power Only Given the relatively small amount of fuel that was available, BECK modeled a power plant with roughly 1 MW of production capacity for both gasification and direct combustion technologies. Using direct combustion technology, a plant would need to sell its power at $192 per MWh to provide an investor with a 15 percent rate of return on their equity. A gasification plant of roughly the same size would have to sell its power for $240 per MWh to provide an investor with the same return. Since the current market price of renewable power in the Roaring Fork region is in the range of $90 to $100 per MWh, neither option is economically feasible. The main reason for this finding is that the capital expense is high relative to the small amount of power produced at a 1 MW plant. In addition, labor costs are roughly the same at a plant of this size as would be incurred at a plant that could produce up to 20 times more power. Thus, there is no economy of scale in terms of labor cost.

1.2.2 Heat and Power Like the preceding analysis, BECK modeled the economic feasibility of using biomass to produce both heat and power. Again, a 1 MW plant was modeled, but it was assumed that 2,000 pounds of steam per hour would be directed to a heat customer. This scenario improves the energy efficiency of the system, but decreases the economic viability because using some of the power for heating means that less power is generated. In other words, the market value of steam heat ($8 per thousand pounds) generates less revenue than using the steam to generate renewable power at the assumed prices.

In a direct combustion application, an investor would need to sell the power from the 1 MW plant at $202 per megawatt hour to realize a 15 percent rate of return on the investment. Again, that price is more than double the current market value of power, so such a project would not be economically feasible. No analysis was performed on a gasification application, since the required selling price for renewable power would be even higher.

1.2.3 Heat Only BECK also investigated the financial viability of using biomass in a heating only application. The system modeled was a heat user that required an average of 1 million BTUs of heat per hour. A direct combustion system was projected to have a simple payback period of 46 years if it was replacing a natural gas fired system in which the cost of natural gas was $1.15 per therm (100,000 BTU). If a grant or other subsidy was available to offset 50 percent of the capital cost, the simple payback would drop to 7.4 years.



A gasification heat only system has a slightly lower capital cost. Therefore, in a similar heating application as that modeled in the direct combustion heat only scenario, the system would have a 21 year simple payback period. The payback period would drop to 5.4 years if 50 percent of the capital cost was covered by a grant. In a different scenario, if a direct combustion or gasification heat-only project were built with no long term financing, and therefore no debt cost, then the projected simple payback would be 8.8 or 7.2 years, respectively.

1.3 RECOMMENDATIONS Given the relatively small amount of fuel available annually, there is little chance that a biomass project that includes the generation of power will be feasible. Therefore, BECK recommends that the Roaring Fork Biomass Consortium work to identify a heating application in which a fossil fuel would be replaced by a biomass fuel. At current price levels, the cost of natural gas is relatively low, which makes the payback on converting to biomass relatively long. The payback can be reduced significantly if grant funds (or other funding sources) are available to offset the upfront capital cost.


CHAPTER 2 – PROJECT BACKGROUND

The Roaring Fork Biomass Consortium (RFBC) is an ad hoc group of regional organizations interested in assessing the use of biomass in small scale heat and power applications. As part of the group’s efforts, a woody biomass supply study was completed in early 2011, which identified approximately 5,800 to 6,600 bone dry tons of woody biomass sustainably available annually in the Roaring Fork Valley (see Figure 1). Note that the supply area is roughly circular in shape and has a radius of roughly 30 miles. The average cost of that fuel delivered to a prospective biomass facility in the region was estimated to be $40.00 per bone dry ton.

Figure 1 – Roaring Fork Valley Biomass Supply Area

Glenwood Springs

Gypsum Eagle

Carbondale Basalt

Aspen

Eagle County

Garfield County

Pitkin County

CHAPTER 2 – PROJECT BACKGROUND


RFBC’s next objective is identifying the commercially available, small-scale technologies that can cost effectively utilize the available biomass to produce heat, power, or both. To assist RFBC in identifying these technologies, the services of The Beck Group (BECK), a Portland, Oregon based forest products planning and consulting firm, was retained. This report provides the findings from that assessment.

BECK’s scope of work included:

1) A technical evaluation of various biomass technologies. The key criteria to be used in the evaluation of these systems includes capital and operating costs, energy efficiency, emissions, job creation, biomass material feeding systems. The objective of the technology assessment is to identify a single biomass technology judged most suitable for implementation in the Roaring Fork Valley.

2) Given the identification of a suitable technology in the technical evaluation, a sample business plan would be developed. The objective of developing the business plan is to provide preliminary information about expected capital costs, required staffing and wage rates, fuel supply costs, and a financial analysis.

The Beck Group appreciates the opportunity to assist in this important work.


CHAPTER 3 – BIOMASS UTILIZATION TECHNOLOGIES

This chapter provides: 1) a broad, descriptive overview of selected biomass conversion technologies2; 2) a discussion of air quality issues; 3) a matrix to allow comparison of the technologies in terms of capital costs, operating and maintenance costs, energy efficiency, emissions, etc. It is important to note that some of the comparisons change based on the scale of the operation. Therefore, for this analysis, the scale of the operation has been assumed to match the amount of biomass fueled estimated to be available in the Roaring Fork Valley.

3.1 DESCRIPTIVE OVERVIEW OF BIOMASS TECHNOLOGIES Figure 2 provides a graphical representation of: 1) the process of converting biomass to fuel/energy; and 2) the various pathways in which the conversion to energy can occur.

Figure 2 – Biofuel and Bioenergy Pathways (adapted from Schuetzle, C.G. 20083)

As shown in Figure 2, there are three “technology platforms” from which biomass can be converted to various forms of energy. The following sections provide a brief description of each technology platform:

1. Biochemical – the use of bacteria, yeasts, and enzymes to break down the carbohydrates found in biomass into useful fuels. Common forms of biochemical conversion are anaerobic digestion to produce methane gas and fermentation to produce ethanol.

2 The descriptive analysis is based on: Market Assessment of Biomass Gasification and Combustion Technology for Small and Medium Scale Applications. July 2009. NREL Technical Report: NREL/TP-7A2-46190. 3 Dennis Schuetzle, et al. 2008. An Assessment of Biomass Conversion Technologies. Accessed at: http://www.redlionbio-energy.com/files/PDF/DOE%20GRIDLEY%20BIOFUELS%20PROJECT%20-%20PHASE%20I%20REPORT%202020080128.pdf

Biomass Feedstock

Woody

Biomass

Agricultural Biomass

Municipal Solid Waste

Energy Crops

Transport, Preparation, &

Handling

Technology Platform

Thermochemical

Biochemical

Direct Combustion

Fuels/ Products

Biodiesel

Bio-Alcohols

Chemicals

Electricity/Heat



2. Chemical – this process differs from biochemical in that rather than a living organism causing a breakdown of biomass into carbohydrates, a chemical catalyst causes the breakdown. A common example is the use of transesterification to convert vegetable oils into bio-diesel.

3. Thermochemical – the process of exposing biomass to heat in order to break it down into various gases, liquids, and solids. The most common thermochemical conversion processes are gasification, direct combustion, pyrolysis, liquefaction, and Fischer-Tropsch.

For the purpose of the technology evaluation for the Roaring Fork Biomass Consortium, BECK considered two thermochemical conversion processes – direct combustion and gasification. In addition, brief attention was given to one biochemical conversion process – anaerobic digestion. The following sections provide a brief overview of how each technology is applied in the conversion of biomass to heat or power.

3.1.1 Biomass Gasification The following sections provide a general discussion of biomass technology and an assessment of the commercialization status of biomass gasification.

3.1.1.1 Technology Description Gasification is the process of breaking down biomass fuels by using heat in an oxygen starved environment in order to produce a combustible gas. In what is called a close-coupled gasification system, the gas produced is almost immediately burned in a nearby combustion chamber. The resulting heat is either used directly for space heating or fed into a boiler to produce steam, which in turn could be used for space heating, a manufacturing process, or power generation. In a two-stage gasification system, the gas is cleaned (tars and particulate matter are removed) before being burned in a gas turbine, or internal combustion engine/generator. The distinction is important because the close-coupled gasification systems are simpler to design, easier to operate, and less costly than two-stage gasifiers. In addition, the process of cooling, cleaning and filtering producer gas in a two-stage system “gives back” much of the potential energy efficiency advantage over direct combustion systems.

A variety of biomass materials, including woody biomass and agricultural residues are suitable feedstocks for biomass gasification. The feedstock is fed into a reactor (an enclosed pressurized container), which is heated, and at the same time the amount of oxygen present in the reactor is limited. As the biomass is heated in this oxygen starved container, volatile gases are released from the wood. The exact composition of the gases vary among processes and feedstocks, but in general, between the temperatures of 395 and 535 degrees Fahrenheit (F), about 60 to 80 percent of the heat content inherent in the biomass is driven off in the form of combustible gases. The gases driven off are called “producer gas” or “syngas” and typically contain about 20 to 50 percent of the amount of energy as an equivalent amount of natural gas (i.e., about 200 to 500 Btu per cubic foot of producer gas). In addition to the volatile gases,



gasification produces carbon char and ash. These materials can be used as a soil amendment.

The producer gas obtained through a gasification process can be used theoretically to more efficiently generate power than generating power with steam. This means that a major advantage of gasification is greater energy efficiency in power production than power production using direct combustion. In addition, gasification technology allows for the utilization of feedstocks (especially certain agricultural residues) that can otherwise be problematic in direct combustion systems. In other words, although fuels with a low ash melting point are problematic in direct combustion systems because the melted ash fouls boiler tube surfaces, the lower operating temperatures of gasification systems largely eliminate this problem.

3.1.1.2 Commercial Status of Gasification Systems The commercialization status of biomass gasification depends on whether the system uses a close-coupled or a two-stage approach. Close-coupled systems, which use unfiltered producer gas to fire a boiler, are a largely proven and commercially available technology. Leading vendors include Chiptec Wood Energy and Uniconfort, which is distributed in the U.S. by Alternative Energy Solutions, a subsidiary of Wichita Boiler. Nexterra is also a vendor of close-coupled systems, but specializes in larger systems. Other companies, such as Primenergy and PRM Energy, have installed close-coupled gasification systems fueled by agricultural residues.

In contrast, the two-stage systems are better classified as being in the developmental and demonstration stage. In such systems, the producer gas must first be conditioned (or cleaned) before being utilized in an engine, turbine, or as a natural gas substitute. The primary technology barriers associated with the two-stage systems are 1) limited ability to efficiently remove impurities from the combustible producer gas and 2) the relatively low heating value of the cleaned producer gas. Community Power Corporation has several two-stage demonstration units in operation. Table 3 is a listing of vendors of gasification systems.

Table 3 – Listing of Direct Combustion System Vendors Company Location System Size Range

AdaptiveARC San Diego, CA 100+ tons of biomass/day Alternative Energy Solutions (CC4) Wichita, KS 1 to 20 Mbtu/hr ChipTec Wood Energy (CC) South Burlington, VT 1.5 to 125 Mbtu/hr Nexterra Energy (CC) Vancouver, BC 7 to 144 Mbtu/hr Primenergy (CC) Tulsa, OK 18 Mbtu/hr PRM Energy Systems (CC) Hot Springs, AR 13 to 118 Mbtu/hr Frontline Bioenergy (TS5) Ames, IA 100 Mbtu/hr Community Power Corp. (TS) Littleton, CO 5 to 100 kW Phoenix Energy San Francisco, CA 0.5 MW to 1.0 MW

4 CC = close coupled gasification 5 TS = two-stage gasification



3.1.2 Direct Combustion The following sections provide a general discussion of biomass technology and an assessment of the commercialization status of direct combustion systems.

3.1.2.1 Technology Description Direct combustion is burning biomass fuel to produce heat, power, or both. It is the most common method of converting biomass into energy. Typically, combustion occurs in a chamber where volatile hydrocarbons are formed and burned. From that process, heat energy is released from the combustion chamber in the form of hot flue gases. Those flue gases are either used directly to provide heat or fed into a boiler to create steam. That steam, in turn, can be used to heat a building, supply heat to a manufacturing process, or generate electricity.

Direct combustion systems coupled with a boiler typically use one of two designs to combust material. These two basic options are: 1) fixed bed system; and 2) fluidized bed system. Fixed and fluidized refer to the manner in which the material is combusted. The majority of biomass boilers use a fixed bed design in which biomass is burned on a grate containing holes. The holes allow for primary combustion air to be introduced below the grate. The most basic designs simply place the fuel in a pile on the grate. While simple, that method creates inefficient combustion. Therefore, more sophisticated designs use a stoker that travels, vibrates, reciprocates, or rotates to spread the fuel uniformly across the grate – thereby, allowing more efficient combustion, and automatically removing the residual ash. Key advantages of fixed bed systems are that they are proven, rugged, efficient, reliable, and have a relatively low capital cost and operating costs. In addition, they are available from a variety of vendors. A key disadvantage is that they typically operate at higher temperatures, leading to higher uncontrolled emissions of some pollutants.

A fluidized bed design, in contrast to feeding material to a grate, feeds biomass into a hot bed of suspended, non-combustible particles such as sand. The injection of high velocity air from underneath the bed distributes and suspends the fuel as it is combusted. Fluidized bed designs are distinguished as either bubbling or circulating, depending on whether or not the hot char (the charcoal-like material left after gasification occurs) exits the bed and is captured and returned to the bed. A key advantage of a fluidized design is that the operating temperatures are lower, which reduces NOx emissions. The key disadvantages are a higher capital cost and higher auxiliary power use.

The energy efficiency of direct combustion is determined by measuring the amount of heat captured in the medium (steam, hot water, or hot air) relative to the amount of heat stored in the fuel, which is known as the heating value. When the flue gases arising from direct combustion are used to heat a space, energy efficiency can range from 65 percent on the low end to well above 90 percent for well designed and maintained systems. However, when direct combustion is used to create steam, which is then used to create power, energy efficiency can range from 15 to 30 percent. When there is a



use for the “waste” heat from direct combustion power generation (known as combined heat and power) energy efficiency can be as high as 70 percent.

3.1.3 Commercial Status of Direct Combustion Systems Direct combustion systems to convert biomass into heat, power, or both are widely available in small, medium, and large applications. Smaller systems have been used extensively for heating purposes. Larger systems are almost exclusively used for power or combined heat and power production. Table 4 is a listing of vendors of direct combustion systems. Note that several manufacturers of very large scale direct combustion systems are not included (e.g., Babcock & Wilcox, Foster Wheeler, ABB, etc.)

Table 4 – Listing of Direct Combustion System Vendors

Company Location System Size Range

A3 Energy Partners Portland, OR 0.25 to 8.5 Mbtu/hr Advanced Recycling Equipment St. Marys, PA 0.75 to 60 Mbtu/hr AFS Energy Systems Lemoyne, PA 3 to 27 Mbtu/hr Bioheat USA (Froling) Lyme, NH .07 to .2 Mbtu/hr Biomass Combustion Systems Worcester, MA 2 to 40 Mbtu/hr Central Boiler Greenbush, MN .25 to 2 Mbtu/hr Energy Products of Idaho Coeur d’Alene, ID 15 to 160 Mbtu/hr Fink Machine (KOB) Enderby, BC .25 to 8.5 Mbtu/hr Heatmor Warroad, MN .45 to .8 Mbtu/hr Hurst Boilers South Coolidge, GA .4 to 56 Mbtu/hr King Coal Furnace Corp. Bismarck, ND 3.4 to 34 Mbtu/hr McBurney Norcross, GA .4 to 56 Mbtu/hr Messersmith Bark River, MI .5 to 10 Mbtu/hr Pro-Fab Industries Arborg, MB .75 to 2.5 Mbtu/hr Propell Energy Jaffrey, NH .5 to 50 Mbtu/hr SolaGen St. Helens, OR .5 to 50 Mbtu/hr Wellons, Inc. Vancouver, WA 5 to 10 Mbtu/hr

3.1.4 Anaerobic Digestion Anaerobic digestion is the use of bacteria to break down organic material (plant and animal wastes) in the absence of oxygen. As the organic material is broken down, gases, including methane and carbon dioxide, are produced. This methane can be collected and used to heat buildings, fuel engines, or generate power. Importantly for this technology, power produced from anaerobic digestion derived methane (biomethane) is considered renewable. Therefore, existing natural gas fired power plants that begin using renewable natural gas to fuel their plants are considered to be producing renewable power. In addition to methane, anaerobic digestion yields digestate – the material left over at the end of the process – which can be used as a fertilizer.



The materials suitable as feedstocks for anaerobic digestion include waste paper, grass clippings, leftover food, sewage, and animal waste. Importantly in the context of the Roaring Fork Valley, woody biomass is generally not a suitable feedstock for anaerobic digestion. This is because the lignin contained in woody biomass cannot be broken down by most anaerobic bacteria.



3.2 BIOMASS AND AIR QUALITY Information about air quality issues associated with small scale biomass projects is limited because many assumptions must be made about the feedstock, the efficiency of the technology, and the installed pollution control equipment. In addition, the importance of air quality concerns differs across regions. Therefore, the following discussion is largely taken from studies of larger scale biomass users. Nevertheless, the findings do provide some level of insight about biomass emissions relative to those from other energy sources.

3.2.1 Carbon While there are some dissenting views6, woody biomass is generally considered to be a renewable and carbon neutral fuel when it is combusted for power generation. This is because the carbon stored in biomass is part of the atmospheric carbon cycle as opposed to terrestrially sequestered carbon stored in the earth as coal and other fossil fuels. Thus, carbon released from combusting biomass is reabsorbed by growing trees that replace the trees which were combusted. The relative levels of atmospheric carbon in the atmosphere or sequestered in biomass are in a constant state of flux, but when measured over time they are in balance or carbon neutral if the fuel is grown sustainably. This conclusion is supported by Figure 3. In fact, for direct fired biomass, the carbon balance is negative based on the biomass being converted to pure carbon dioxide rather than other more damaging hydrocarbons (e.g., methane) that occur in a natural decomposition process or landfilling.

Figure 3 – Life Cycle Greenhouse Gas Emissions

-600

-400

-200

0

200

400

600

800

1000

1200

DedicatedBiomass IGCC

Average PCCoal

Coal/BiomassCofiring

Direct-FiredBiomassResidue

Natural GasCombined

Cycle

GW

P (g

CO

2-eq

uiva

lent

/ kW

h)

Source: Mann, Margaret and Pamela Spath, “A Comparison of the Environmental Consequences of Power from Biomass,

Coal and Natural Gas,” National Renewable Energy Laboratory, Golden Colorado.

6 Biomass Sustainability and Carbon Policy Study. 2010. Prepared for the Commonwealth of Massachusetts by the Manomet Center for Conservation Sciences. Accessed at: http://www.manomet.org/sites/manomet.org/files/Manomet_Biomass_Report_Full_LoRez.pdf



Morris (1999) reports similar results in “The Value of the Benefits of U.S. Biomass Power.” Morris compares different disposal techniques (i.e., composting, spreading, and open burning), as well as energy production methods (coal and gas) to biomass energy production.7 Similar results have also been reported from studies evaluating biomass from other types of woody debris. Specifically, Spitzley and Keoleian reported similar greenhouse gas emission levels in their evaluation of Willow biomass electricity production.8

3.2.2 Other Emissions Despite the carbon neutrality of biomass combustion, there are still air quality concerns associated with its use. Morris reports specific air pollutant emission levels for biomass and coal in terms of pounds of emissions per bone dry ton of fuel combusted. As shown in Table 5, biomass has lower emissions for NOx and SOx, but higher emissions for particulates and carbon monoxide (CO). Note that the far right column shows the pounds of emissions that would be released into the atmosphere by combusting the amount of fuel available in the Roaring Fork region (~6,000 bone dry tons). Note also that the biomass emissions data is from averages at 34 California direct combustion biomass facilities (23 grates and 11 fluidized-bed burners), many of these installation now well over 20 years old. Therefore, the Roaring Fork emissions figures should only be considered as rough estimates. The actual estimate levels would vary depending on the specific technology used in the region.

Table 5 – Emissions from Biomass Energy Plants (Pounds of Emissions per Bone Dry Ton for Biomass)

Emission Type

Biomass (Direct

Combustion) Coal

Annual Pounds of Emissions in

Roaring Fork Region

NOx 2.5 3.1 15,000

SOx 0.15 3.5 900

CO 7.5 1.0 45,000

Particulates 0.45 0.14 2,700

Source: Morris, Gregory, The Value of the Benefits of U.S. Biomass Power, Green Power Institute, Berkeley, California, National Renewable Energy Laboratory, NREL/SR-570-27541, November 1999.

7 Morris, Gregory, The Value of the Benefits of U.S. Biomass Power, Green Power Institute, Berkeley,

California, National Renewable Energy Laboratory, NREL/SR-570-27541, November 1999, Table 2. 8 Spitzley, David and Gregory Keoleian, Life Cycle Environmental and Economic Assessment of Willow

Biomass Electricity: A Comparison with Other Renewable and Non-Renewable Sources, Report No. CSS04-05R, March 25, 2004 (revised February 10, 2005).



3.3 TECHNOLOGY COMPARISON MATRIX Table 6 provides a comparison of the relative strengths and weaknesses of direct combustion and gasification technologies for converting biomass to energy. It is important to note that the comparison is made between direct combustion and gasification, not between biomass and other fuels that are used to generate electricity.

Table 6 – Comparison of Direct Combustion and Gasification Strengths and Weaknesses

Strengths Weaknesses

Direct Combustion

• Proven, simple, lower-cost

technology

• Equipment is widely available, complete with warranties

• Fuel flexibility in moisture content and fuel particle size

• Lenders comfortable with technology

• Greater NOX, CO, and particulate emissions

• Inefficient conversion process when generating power alone – some advanced designs are improving efficiency

• Can require significant amounts of water if generating power with a steam turbine

Gasification • Lower NOX, CO and particulate emissions

• Potential for more efficient conversion process when generating power

• Virtual elimination of water needs if generating power without a steam turbine (excluding close-coupled systems)

• Technology is in the development and demonstration phase (close-coupled systems excluded)

• Need fuel of uniform size and with low moisture content

• No substantial vendor guarantees


CHAPTER 4 – ECONOMIC COMPARISON OF TECHNOLOGIES

As described in the Project Background section of this report, there is between 5,800 and 6,600 bone dry tons of biomass fuel estimated to be available annually in the project study area. In addition, that fuel could be delivered to a biomass facility for an average cost of $40.00 per bone dry ton. In the following report sections, BECK has completed “high-level” economic assessments for using direct combustion and gasification technologies to generate power only, heat and power, and heat only – given the amount of fuel available,.

It is important to note that operating and capital costs are very project specific. Since no specific sites and applications have been identified in the Roaring Fork area, the following assessments are based on normative assumptions of factors such as interconnection, heat loads, fuel costs, etc. The intent is to illustrate the relative economics associated with each technology and application (power, heat, or both).

4.1 POWER ONLY 4.1.1 Direct Combustion For this analysis, BECK modeled a 1.2 MW biomass plant that uses direct combustion technology. Such a system requires 11,000 bone dry tons per year, which is more fuel than the roughly 6,500 bone dry tons that is estimated to be available in the Roaring Fork region. Nevertheless, BECK elected to model such a scenario because data about operating and capital costs for such a system was readily available.

To account for the extra fuel required, BECK assumed that 4,500 bone dry tons could be delivered from areas beyond the Roaring Fork Valley at an average cost of $60 per bone dry ton. Thus, the weighted average cost of the fuel assumed in this analysis is $48.25 per bone dry ton (6,500 BDT @ $40/BDT and 4,500 BDT @ $60/BDT). The 6,500 BDT at $40 per bone dry ton delivered is per the TSS fuel supply study.9

It is important to note that a 1.2 MW plant is small relative to most biomass plants, which typically range in size from 5 MW to 40 MW or more. The reason larger plants are more common is that the non-fuel operating costs (primarily labor) do not change significantly as plant size increases. In other words, roughly the same amount of labor is needed for a 5 MW plant as a 20 MW plant, as an example.

In BECK’s experience, the cost of producing biomass fueled power at plants in the 1.2 MW size range is simply too costly to be sold to the grid as renewable power. This conclusion is illustrated by the information in Table 7.

9 Wood Fuel Availability Analysis for the Roaring Fork Valley, Colorado. TSS Consultants, Rancho Cordova, CA March, 2011.



Table 7 – Estimated Cost of Producing 1.2 MW of Biomass Power Using a Direct Combustion System

Expense Item

Annual Expense (Dollars)

Power Produced (Megawatt Hours)

Cost ($ per MW Hour)

Fuel 528,000 9,800 53

Labor 334,000 9,800 34

Consumables 110,000 9,800 11

Utilities, Property Tax, & Insurance 210,000 9,800 21

Depreciation 541,000 9,800 55

Total 1,723,000 9,800 175

Note that in the table the total cost per megawatt hour is estimated to be $175. Since the figures in Table 7 only reflect cost, the price a power plant developer would need to be paid is $192 per megawatt hour to earn a 10 percent internal rate of return on his or her investment (assuming 10 percent discount rate, 10 years, and that the owner has 100 percent equity in the project). That power sales price provides a total annual revenue of $1.890 million in year 1 (power purchase agreements typically escalate the price of the power over the life of the contract).

BECK estimates that the current market value of renewable biomass power in the Roaring Fork region is between $90 and $100 per mWh. Thus, given the small power plant size necessitated by the small amount of available fuel, it is not possible to produce biomass power in the Roaring Fork region using direct combustion technology at a cost low enough to allow for the sale of renewable power to the grid.

The important assumptions included in the preceding analysis are:

• The power plant modeled in the analysis had a 1.2 MW gross power production capacity and 1.1 MW net power production capacity. Steam flow was estimated to be just over 16,000 pounds per hour, with a steam pressure of 400 psi and 750 degree Fahrenheit steam.

• The labor cost included 5 staff: 1 general manager and 4 technicians. The plant would operate essentially 24 hours per day and 7 days per week. Thus, one person would be at the plant at all times. The labor cost shown is the “fully loaded” cost, which includes wages and benefits.

• The consumables category includes materials and costs incurred for chemicals needed to treat boiler and cooling tower water, ash disposal, routine maintenance, etc.



• The all inclusive capital cost (equipment, construction, engineering, permitting, site prep, interconnection, and financing) was estimated to be $5.413 million.

• The plant modeled was a direct combustion system that required 11,000 bone dry tons of fuel annually. It is also important to note that if the plant size was reduced to match the available fuel in the Roaring Fork region, the number of megawatt hours of power produced would roughly be cut in half. At the same time, many of the other costs would only decrease slightly or not at all. The result would be a power production cost even higher than that shown in Table 7.

• The analysis assumed a federal production tax credit valued at $0.011 per kilowatt hour in year one, escalated at 3 percent annually. No other grants, credits, or special financing packages were used in the analysis.

4.1.2 Gasification BECK performed a similar analysis for a 1 MW gasification power only system. Such a plant requires 9,000 bone dry tons of fuel annually. For the system to operate effectively, the fuel needs to be dried to about 10 to 12 percent moisture content before it enters the gasification chamber. Waste heat from the internal combustion engines (which generate the power) is used to dry the fuel. The system is a two-stage gasification system. This is because the producer gas is first cleaned and then used in an internal combustion engine to produce power.

The system capital and operating costs were supplied by Phoenix Energy of San Francisco, CA (see Appendix 1 for more information about Phoenix Energy). The capital cost of their system is $5.3 million. Their systems typically operate about 7,500 hours per year. As shown in Table 8, the cost of producing power using a gasification system is estimated to be $240 per megawatt hour. The price a developer would have to be paid to earn a reasonable return on their investment would be even higher. Thus, like direct combustion, the cost of producing power using gasification technology at such a small scale (1 MW) is much higher than the current market value of power.



Table 8 – Estimated Cost of Producing 1 MW of Biomass Power Using a Gasification System

Expense Item




Fuel 410,000 7,500 55

Labor 334,000 7,500 45

Property Tax, Ins., & Misc. Supplies 250,000 7,500 33

Routine Repair 188,000 7,500 25

Major Repair 100,000 7,500 13


Total 1,811,500 7,500 242

4.1.3 Other Power Market Options Besides selling power to the grid, another option often considered is selling power to an industrial customer. In BECK’s experience, this scenario rarely works. The reasons for this are that few industrial customers have the type of electrical load shape that is well suited to a biomass power plant. In other words, a biomass fueled power plant runs most efficiently when it is operated 24 hours per day, 7 days per week and a consistent amount of power is produced. Many industrial customers, by contrast, have power needs (loads) that peak only during certain operations, and then the load drops off substantially during other times. Thus, the stable power production of a biomass power plant generally is not well suited to meeting the needs of a single large customer that has varying demands for power over time.

In addition, very large industrial customers typically negotiate with their utility to obtain a power purchase rate that is correctly only slightly higher than the wholesale value of the power purchased by their utility provider. Thus, in many cases, the price at which a large industrial customer purchases power is lower than the wholesale market value of renewable power.

4.2 COMBINED HEAT AND POWER 4.2.1 Direct Combustion In this scenario, BECK assumed the same 1.2 MW system that was modeled in the Power Only scenario (Section 4.1). However, for this scenario, a heat customer is added so that what is modeled is a combined heat and power application using direct combustion technology.

Since no actual heat customer has been identified in this project, BECK assumed that a hypothetical heat customer exists and requires an average of 2,000 pounds of low pressure (15 psig) steam per hour. Note that such a heat load is roughly the equivalent



of the Glenwood Springs Community Center’s heating needs during peak heating requirements.

Table 9 illustrates the key costs associated with this scenario.

Table 9 – Estimated Cost of Producing Power in a CHP Scenario Using Direct Combustion Technology

Expense Item




Fuel 528,000 9,364 56

Labor 334,000 9,364 36

Consumables 110,000 9,364 12

Utilities, Property Tax, & Insurance 210,000 9,364 22


Total 1,723,000 9,364 184

Note that in terms of dollars, the costs have not changed from the power only scenario. However, some of the steam that was used to generate power is now being used to supply a heating load. Extracting 2,000 pounds per hour of low pressure steam to supply a heat load reduces the power output from 1.2 MW to about 1.14 MW. Thus, there are fewer megawatt hours of power available for sale in this scenario as compared to the power only scenario (9,364 MWh in the CHP scenario versus 9,800 MWh in the power only scenario). The costs have not changed in terms of dollars, but the number of megawatt hours produced is less, so the cost per megawatt hour is higher.

Offsetting the reduced power sales is the sale of steam to the heat user. For this analysis, it was assumed that the heat customer would pay $8.00 per thousand pounds of steam or about $8.00 per million BTUs. That price is roughly equivalent to natural gas priced at $0.66 per therm. The national average commercial price for natural gas in May 2011 was $0.91 per therm. Thus, in this scenario, the heat customer would save nearly $44,000 per year in heating costs ($0.25/therm x 10 therm/MMBTU x 1 MMBTU/thousand pounds of steam x 2 thousand pounds of steam/hour x 8,760 hours/year).

Similar to the power only scenario, the $184/MWH (in Table 9) reflects only the costs. Therefore, in order to provide a project developer with a 10 percent internal rate of return on his or her investment, the power purchase price would have to be $202 per megawatt hour (assuming 100 percent equity, a 10 percent discount rate, and a 10 year timeline). The total annual revenue (power and steam sales would be $1.893 million/year). Thus, similar to the other scenarios already considered, the financial analysis of a combined heat and power application does not support the conclusion that producing heat and power at a small scale is economically feasible.



4.2.2 Gasification Given that the analysis of a power only gasification scenario was not economically feasible, and since “robbing” some of the energy from the power production system for a heating application will only cause the price at which power can be sold to rise, no analysis of a gasification combined heat and power system was completed.

4.3 HEAT ONLY 4.3.1 Direct Combustion In this scenario, BECK modeled the economics of utilizing woody biomass in a heating only application. Since no specific heating application has been identified as part of this study, a constant heat load of 1.0 million BTU/hour was assumed, which is roughly equivalent to the annual average heating needs of the Glenwood Hot Springs Community Center. If more specific information about a site was available in terms of the size of the building and the heat load, the approach would be to determine the number of heating degree days needed for the structure and design the heat supply accordingly.

To assess the economic feasibility of this scenario, BECK reviewed the capital costs of 6 projects in which building heating systems were retrofitted to direct combustion biomass boilers from fossil fuel boilers. The average capital cost per million BTUs/Hr for those projects was $289,000, including equipment and installation.

All of those projects occurred several years ago. Therefore, in this scenario, the average capital cost was escalated by 1.10 to account for higher current capital costs. Thus, in this scenario, it is estimated that the capital cost for the hypothetical 1.0 MMBTU/Hr system would be $318,000. Note that the boiler size modeled is equal to the annual heat requirement and not the peak demand requirement. This was done purposefully under the assumption that the existing natural gas system would be used as a back up during peak demand periods and during the spring and fall when lower heat demands lead to inefficient operation of a wood-fired boiler. A total of $225,000 in costs was assumed for other aspects of the project, including engineering and permitting costs ($75,000) and integrating an existing system with a new biomass system ($150,000). Thus, the total project cost was assumed to be $543,000 ($318,000 plus $225,000). Table 10 shows that a wood fired boiler would yield an annual savings of nearly $12,000 dollars over the existing natural gas fired system. The projected simple payback for this scenario is 46 years ($543,000/$11,922).

In addition Table 10 shows that if there were no long term financing for the project, and therefore no debt cost, then the annual savings would be just over $61,000 and the projected simple payback drops to 8.8 years ($543,000/$61,471).



Table 10 – Financial Analysis Heat Only Direct Combustion System

Cost Item

Annual Cost/Savings

(with debt)

Annual Cost/Savings

(without debt) Units

Capital Cost 543,000 543,000 Dollars

Annual Operating Costs

Labor 4,000 4,000 Dollars

Maintenance 2,000 2,000 Dollars

Biomass Fuel 15,000 15,000 Dollars

Electricity 1,617 1,617 Dollars

Debt Service 49,548 0 Dollars

Total Annual Operating Cost 72,165 22,617 Dollars

Potential Savings (Existing System Annual Natural Gas Cost) 84,088 84,088 Dollars

Total Annual Operating Costs (Wood) 72,165 22,617 Dollars

Annual Savings 11,922 61,471 Dollars

Simple Payback 46 8.8 Years

Please note that the economic argument for converting to a biomass fueled system would be improved if a grant (or other source of funding) was available to offset a portion of the capital cost. To test the sensitivity of the project to grant funding availability, BECK also modeled a scenario in which a grant reduces capital cost by 50 percent. In such a scenario, the amount financed is reduced to $271,500. This in turn reduces the debt service payment to $24,774 annually, which in turn increases the annual savings to about $36,700, creating approximately a 7.4 year simple payback ($271,500/$26,700).

The key assumptions associated with the preceding analysis are:

• Labor – an existing maintenance person would spend 10 percent of his/her time (200 hours) per year maintaining and operating the boiler.

• Fuel – the boiler would require 375 bone dry tons of fuel annually. Note that this assumes that the existing natural gas boiler would be used as a back-up and would operate 20 percent of the time – during the spring and fall “shoulder seasons” when the lower heating demands translate into inefficient operation of a wood-fired boiler.



• Power – the power cost is based on 32,300 kilowatt hours of energy being used per year to operate the wood-fired system (i.e., power for fan motors, fuel conveyors, augers, etc.) The cost of power was assumed to be $0.05 per kilowatt hour.

• Debt Service – assumes that 100 percent of the capital cost would be financed at a rate of 7.5 percent for a period of 20 years. Note also that this scenario assumes that no grant funds are available to offset the initial capital cost.

4.3.2 Gasification Like the preceding scenario, BECK modeled the economics of utilizing woody biomass in a heating only application, but using gasification technology. All other assumptions used in the direct combustion heat only analysis are the same here. For this analysis, BECK reviewed the installed costs of biomass heating systems that use gasification technology and concluded that the installed cost averages $200,000 per million BTUs/Hr of heating capacity, which is lower than direct combustion technology. The results of the financial analysis are displayed in Table 11. They show a simple payback period of 21 years with no grant funding to offset capital costs. If a grant equal to 50 percent of the capital cost was available, the payback period would drop to 5.4 years. If there was no long-term debt associated with the project, the payback period would drop to 7.2 years.

Table 11 – Financial Analysis Heat Only Gasification Combustion System

Cost Item

Annual Cost/Savings

(with debt)

Annual Cost/Savings (without debt) Units

Capital Cost 445,000 445,000 Dollars

Annual Operating Costs

Labor 4,000 4,000 Dollars

Maintenance 2,000 2,000 Dollars

Biomass Fuel 15,000 15,000 Dollars

Electricity 1,617 1,617 Dollars

Debt Service 40,606 0 Dollars

Total Annual Operating Cost 63,223 22,617 Dollars

Potential Savings (Existing System Annual Natural Gas Cost) 84,088 84,088 Dollars

Total Annual Operating Costs (Wood) 63,223 22,617 Dollars

Annual Savings 20,865 61,471 Dollars

Simple Payback 21 7.2 Years


APPENDIX 1

Basic Process Description The Phoenix Biomass Energy system converts wood and agricultural waste biomass into a natural gas substitute

(“syngas”) through the process of thermo-chemical conversion (“gasification”). This syngas is then used to fuel

a specially modified natural gas genset that produces renewable electricity and heat. A byproduct of the

gasification process, called “biochar”, is a wood char that has sequestered carbon in solid form (~74% fixed

carbon) and is used as a beneficial soil amendment.

The biomass conversion process is a thermo-chemical one that „cooks‟ biomass in an oxygen starved

environment. By depriving the fuel of sufficient oxygen, the wood biomass does not burn, but rather gives off a

hydrogen rich syngas. As the biomass gives off the syngas, it is transformed into bio-char and ash of

approximately 1-5% of the volume of biomass fuel. The syngas is then captured, cleaned and cooled before

being sent as fuel to the genset. The gensets we utilize come from variety of nationally known vendors such as

Cummins, Caterpillar, and GE. This ensures that there are readily available spare parts and maintenance

technicians available locally. Further, we have incorporated an on-site water treatment as part of our core

model, re-using much of the water for cooling and filtration process, to maintain a small footprint. Finally, our

largest by-product, the biohcar, is sold to a variety of potential users.

One unique aspect of our system is that the footprint is very small – less than half an acre to generate 1

megawatt; versus wind systems that need 1-2 acres per MW, or solar which needs 8-10 acres per MW. Along

with our module design, this small footprint allows our solution to be deployed close to the biomass feedstock.

Fuel Preparation

Fuel storage and handling is finalized with your company or host‟s personnel prior

to site work being carried out. There are several design options to choose from,

which complement a site‟s material flow. Currently, we believe a walking floor

trailer and/or a combination conveyor fed hopper provide the most flexible

solutions. Biomass fuel from your facility will be delivered via conveyer (or front-

end loader, ) to the fuel hopper. Once in the Phoenix Energy hopper, our automated

system uses a robust transloading platform and fuel metering sensors to

continuously feed the conversion unit in small batches as needed.

Biomass Conversion

The biomass conversion chamber (figure 1) is essentially a chamber where various

complex thermo-chemical processes take place. As the material flows downward

through the reactor, the biomass gets dried, heated, converted into gas and reduced

into bio-char and ash.

Although there is a considerable overlap, each process can be considered to occupy

a separate zone, where fundamentally different chemical and thermal reactions take

place. The fuel must pass through all of these zones to be completely converted.

Figure 1

2

Figure 2 – The P250 biomass conversion chamber (red) and filtering system (blue)

Figure 3 – A P500 installation in California

The downdraft conversion unit, employed by Phoenix Energy, is under negative air drawn by a high-pressure

blower. The essential characteristic of the downdraft design is that the tars given off in the heating zone are

drawn through the conversion zone, where they will be broken down or oxidized. When this happens, the

energy they contain is usefully recovered with the mixture of gases in the exit stream being relatively clean, and

ready for further processing. Expected total gas contaminant concentration prior to filtration is up to 100 times

lower than what is often seen in updraft and fluid-bed systems.

Gas Cleansing

After the syngas has been extracted from the

conversion chamber it is cooled and cleaned by a series

of scrubbers and filters. First, the gas passes through a

venturi scrubber, which is known to remove particulate

in the sub-micrometer range. The gas is then passed

through a series of four filters. The first is a coarse

filter to coalesce residual liquids. The second is a

rejuvenating active sawdust filter, the third is a similar

passive filter, and the fourth is a fabric bag filter. The

filter media are sawdust and biomass chips so instead

of using expensive synthetic filters that need to be

thrown away, the used filter media can be simply

placed back into the fuel hopper and consumed.

Power Generation

Phoenix Energy units are based on a spark-ignited engine genset. Depending on the size chosen, the engines are

capable of providing 500 or 1,000KW operating on syngas. Phoenix Energy will customize the selected genset

to allow syngas carburetion for this engine and provide standard paralleling switchgear for electrical output.

At present we believe the CAT 3516

or the Cummins 1710 offer the most

attractive engine options for your firm,

however we can work with any natural

gas genset. First and foremost there is

a large secondary market for CAT and

Cummins engines and the service

coverage in the US is very good.

These engines also have unique

features enabling good fuel economy,

better emissions, high durability, and

extended oil / filter change periods.

They run on variety of gaseous fuels

like natural gas, bio-gas, sewage gas,

LPG etc. Engines are available in both

types of aspirations, naturally aspirated

and turbocharged, after-cooled

3

versions. Both CAT and Cummins engines have been designed to combine compact size, low emission levels

and excellent performance characteristics of high-speed technology with the medium speed benefits of water-

cooled exhaust valve seats, steel-crown pistons & combustion control.

Bio-char & ash handling, and Low Water usage

Bio-char & ash are removed from the conversion chamber using a dry extraction process designed around a

water cooled auger at the base of the gasifier. Scrubbed particulate in the form of ash is extracted at the base of

the cyclone. A closed water loop is used for both cooling and process water. On-site water treatment, utilizing

biochar and sand filters allows for recirculation of both water loops reducing water usage to a minimum. In

fact, at certain times of the year the system is actually water accretive as moisture is removed from the biomass

and captured in the process water loop. Water levels are maintained in separate storage tanks for each loop and

pumped through both the cooling and filtration process. The automated filter is typical for river sludge

treatment and separates the solids from the re-circulated water. The biochar , is a “capture & store” byproduct

that is separated out, using a special mechanical separator, for resale as a soil amendment or ADC, sequestering

carbon in solid form while in the ground for up to 1,000 years! While we don‟t include these biochar sales in

our conservative base financial forecast, we do believe that carbon credits related to biochar may become a

valuable revenue source in the near future. Water leaving the filter is passed through a final stationary filter

prior to heat exchange. The scrubbing water is absorbing heat from the syngas and must be cooled in a cooling

tower prior to returning to the closed-loop scrubber.


APPENDIX 2

Turning Biomass into Energy since 2003

What we do Phoenix Energy manufactures & installs on-site

biomass waste fueled power plants.

•  Our power plants convert waste biomass into a hydrogen rich gas which is used to produce electricity and heat.

•  Our primary partners are municipal solid waste operators, agricultural producers, and wood based manufactures.

The Problem We Solve •  Eliminate energy costs (heat &

electricity) •  Reduce disposal costs •  Greening of your enterprise •  Provide energy security

Plus! •  Sell excess electricity back to

the grid •  Receive Renewable Energy

Certificates, tax credits, & other incentives

•  Carbon sequestration

Our Product

•  Turnkey biomass power plants

•  Tight footprint 50’x25’

•  Engine can be housed separately

•  Modular •  Self contained

Before

7-10% line loss

CO2, NOx, SO2, Hg emissions

1.5% pipeline leakage

Trucking Emissions

•  700 tons CO2

•  1 ton CO

•  4.4 tons NOx

Power shipped in, waste shipped out

After

CO2, NOx, SO2, Hg emissions

1.5% pipeline leakage

Export power for 800 local homes – no transmission losses

•  120,000 fewer truck miles annually

•  20,000 fewer gallons of diesel burned

Carbon sequestration - ADC or soil amendment for local farms 7-10%

line loss

Local power for local customers

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