final report draft warrenton biomass project

Feasibility Study for a Small-Scale Biomass Project for the Warrenton, VA Area Final Report (Draft) Contract Reference: 33.001 Prepared by: Kevin Comer, Billy Broas, Chris Lindsey, Anneliese Schmidt, and Kathleen King Date: November 2, 2007

Warrenton Bioenergy Assessment ANTARES Group Inc.

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TABLE OF CONTENTS

1 EXECUTIVE SUMMARY ...................................................................................................................................1 2 FEEDSTOCK SUPPLY STUDY........................................................................................................................4

2.1 PRELIMINARY SCREENING.............................................................................................................................5 2.2 ANALYSIS METHODOLOGY ..........................................................................................................................17 2.3 INTERVIEW RESULTS ...................................................................................................................................20 2.4 DATA ANALYSIS ...........................................................................................................................................24 2.5 FUEL SUPPLY STUDY CONCLUSIONS & RECOMMENDATIONS....................................................................30

3 LEGAL, PERMITTING AND REGULATORY ISSUES ...............................................................................32 3.1 PRELIMINARY ACTIONS FOR THE INTEGRATED BIO-REFINERY PROJECT AND RESULTS ...........................33 3.2 LOCAL ISSUES .............................................................................................................................................35 3.3 FEDERAL REGULATORY PROGRAMS AND PERMITS....................................................................................38 3.4 STATE PERMITS AND LICENSES ..................................................................................................................39

4 TECHNOLOGY ASSESSMENT .....................................................................................................................43 4.1 PROTOTYPE CONVERSION PLANT CONFIGURATION, COST AND PERFORMANCE .....................................44 4.2 LIGNOCELLULOSIC BIOMASS TO MIXED ALCOHOLS: THERMOCHEMICAL CONVERSION ............................45 4.3 POWER GENERATION ..................................................................................................................................48

5 ECONOMIC ANALYSIS...................................................................................................................................54 5.1 ETHANOL......................................................................................................................................................54 5.2 POWER.........................................................................................................................................................57

6 RURAL ECONOMIC IMPACTS OF A SMALL-SCALE BIOREFINERY .................................................58 APPENDIX A.............................................................................................................................................................61 APPENDIX B.............................................................................................................................................................63 APPENDIX C.............................................................................................................................................................69 APPENDIX D.............................................................................................................................................................72


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1 Executive Summary Project Background At the request of Mayor George Fitch, ANTARES has performed a feasibility study for several biomass-to-energy options that could be located in the town of Warrenton, Virginia. The projects could produce enough electricity or fuel from local wastes and biomass residues to allow Warrenton and even Fauquier County to take a giant step towards energy independence. The Mayor’s intent is to encourage the development of a local bioenergy project that reduces the environmental footprint of local energy use by converting locally available biomass and/or waste materials into useful energy products, while also reducing the footprint and environmental impact of waste disposal in the area. The project could serve as a template for other communities and thereby provide an important element of a new approach to reducing our nation’s dependence on foreign oil and reducing greenhouse gas emissions. This report summarizes the results from the investigation. What follows is a review of the major findings from the research performed by ANTARES that will serve to assist Mayor Fitch in his venture to construct a bioenergy facility. Feedstock Supply Results The study performed by the ANTARES GROUP was two-phased. Phase 1 was a feedstock supply study that identified the types and quantities of biomass feedstock available within a 25 to 50 mile radius of Warrenton. This included municipal solid waste (MSW), non-recyclable commercial debris at the landfill, wood residues, and used tires. The steps taken by ANTARES can be summarized by the following points: • Identified biomass feedstock available in 25 and 50 mile radius • Collated quantity and price information on feedstock that could be available for use by a

bioenergy project • Contacted landfills in the area to acquire level of interest in being suppliers • Used results from the feedstock supply study to run financial analyses on varying

scenarios for electricity and biofuel projects • Summarized key results that show the feasibility of the projects considered based on

different economic assumptions The feedstock supply study identified up to 250 to 300 tons/day available from the Fauquier landfill. An additional 320 tons/day could be gathered from the neighboring counties of Rappahannock and Culpeper (~ 20 miles from Warrenton). The landfill operators from each county were contacted via phone and each one showed willingness to divert their waste to an energy project in Warrenton. Based on the preliminary economic analysis in this study, these resources would likely be the primary feedstock for the biorefinery because of their availability and the negative cost. Fauquier County could share the $46/ton tipping fee with


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the biorefinery in exchange for their avoided costs for landfilling. The Culpeper transfer station expressed a willingness to pass on their tipping fee of $40/ton. An additional 15,000 tons of woody biomass was identified as generated in the area based on a recent survey conducted by Virginia Tech. Most of this is wood chips, sawdust, and scraps left over from manufacturing operations. The weighted average delivered cost of these feedstocks is $20/ton. Several woody biomass generators in the area were contacted and showed interest in sending their residues to the biorefinery. Many of these operations generate wood residues as a waste product and are looking for someone to cheaply transport it away. Technology Characterization and Economic Analysis Phase 2 of the project consisted of exploring the economic feasibility of an energy plant, using the fuels investigated in Phase 1 as a feedstock. With the assistance of Pacific Northwest National Laboratory (PPNL), different technologies were examined to determine the potential process to use for a small scale integrated Biorefinery. Efforts were focused on evaluating different types of energy plants that can produce either liquid fuels or electricity. It was assumed that the available feedstocks can be used for the production of either end product. In each scenario, MSW was assumed to earn a tipping fee of $13/ton. This is the avoided cost of paying the landfill operator who would otherwise bury the MSW. Wood residues were set at a cost of $6.40/ton and assume using a portion of the Construction and Demolition wood from the landfill as well as wood chips bought from millworks. Lignocellulosic Biomass to Mixed Alcohols: Thermochemical Conversion A small scale, 250 ton/day Biorefinery based on gasification and conversion to ethanol and mixed alcohols would produce on the order of 6 million gallons per year (MGY) of product. At a capital cost of $72 million and an IRR of 10% it would require a wholesale ethanol sales price of $2.12/gal for MSW and $2.52/gal for C&D/Wood. If a grant of $30 million were provided by one of several DOE or USDA programs, the wholesale ethanol price would be $1.07/gal for MSW and $1.47/gal for C&D Wood. A similar plant with a $46 million capital cost would require a wholesale price of $1.29/gal for MSW and $1.70/gal for C&D/Wood. A $23 million grant would lower the Wholesale Price to $0.58/gal for MSW and $1.00/gal for C&D/Wood. If the plant could be constructed for $30 million, it would require a wholesale price of $0.79/gal for MSW and $1.19/gal for Wood. A $15 million grant would lower the price to $0.38/gal for MSW and $0.79/gal for C&D/Wood. A summary of these high, moderate, and low capital cost scenarios is shown in Figure 1. It displays the wholesale ethanol price for each of these cases at varying feedstock costs. The high-cost case mentioned above and shown in Figure 1 reflects additional costs associated with the construction and start-up of a pilot plant for a technology that has not previously been demonstrated at a commercial scale or on a fully integrated basis. This is currently the situation for thermochemical conversion of biomass to ethanol. The moderate cost scenario reflects reduced costs that could be expected according to published reports at a time in the near future after the technologies have been demonstrated on both a pilot and commercial-scale. The low cost scenario represents potential future capital costs once the technology has fully matured, significant value engineering has occurred, and all required components and materials are readily available. A government grant would very likely be less applicable in that scenario.


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Figure 1. Capital Costs and Wholesale Ethanol Price ($/gal) for Different Cases

Feedstock Type and CostProject Construction Scenario Turnkey Capital $ MSW ($40)/ton MSW ($13/ton) Wood $6.40/ton Wood $30/ton

High Cost $72,000,000 $2.18 $2.74 $3.14 $3.62Moderate Cost $46,000,000 $1.12 $1.68 $2.08 $2.56Low Cost $30,000,000 $0.49 $1.04 $1.44 $1.92

High Cost $40,000,000 $0.84 $1.39 $1.79 $2.27Moderate Cost $23,000,000 $0.21 $0.76 $1.16 $1.65Low Cost $15,000,000 $0.00 $0.48 $0.88 $1.37*50% gov't cost share, or $30 million (whichever is less)Wholesale price represents requirement to achieve 0 NPV on investment, after meeting an assumed required weighted cost of capital of 13.9%Note: $0.60/gal tax credit, mixed alcohol by-producst @ $1.50/gal

With No Government Grant Assistance

*With a Government Grant

Municipal Power Generation A 250 ton/day gasification to steam power plant with a capital cost of $41 million and an IRR of 10% would require a wholesale electricity price of $117/MWh (11.7 ¢/kWh) for MSW and $106/MWh (10.6 ¢/kWh) for C&D/Wood. If a $20.5 million federal grant were provided the price of power would drop to $68/MWh (6.8 ¢/kWh) for MSW and $64/MWh (6.4 ¢/kWh) for C&D/Wood. A summary of the different technologies evaluated with their respective capital costs and wholesale electricity prices for varying feedstock costs is shown in Figure 2. Figure 2. Capital Costs and Wholesale Electricity Prices ($/MWh) for Different Cases

Feedstock Type and CostProject Technology Scenario Turnkey Capital $ MSW ($40)/ton MSW ($13/ton) Wood $6.40/ton Wood $30/ton

Stoker Plant $36,934,332 $100 $130 $115 $141Gasification to Steam $40,627,766 $116 $145 $129 $154Gasification to Engine

Stoker Plant $60,000,000 $109 $133 $114 $135Gasification to Steam $66,000,000 $125 $149 $128 $154Gasification to EngineWholesale price represents requirement to achieve 0 NPV on investment, after meeting an assumed required weighted cost of capital of 13.9%

250 Tons/Day

400 Tons/Day

Regulatory Outlook Based on the information for the regulatory agency processes concerned with approval of an integrated bio-refinery designed to produce both electricity and bio-fuel, it would appear that a reasonable time frame between selection of the technology to be used and its facility design completion and ground breaking should be between fifteen and twenty-four months, contingent on the availability of appropriate machinery. Importing new quantities of MSW from neighboring counties could be met with public opposition in this very affluent area. Steps should be taken early on to communicate to the community the purpose and benefits of building a Biorefinery based on biomass from the MSW stream. Determining the impacts of truck traffic on proposed sites is another area of concern that must be addressed early in the development process.


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2 Feedstock Supply Study Objectives ANTARES has conducted an extensive review of potential biomass supplies around the location of the proposed Warrenton power plant. The study is designed to determine whether there is a large enough supply of biomass available to support a 250-500 ton/day biomass-to-energy facility. The target fuel types for such a facility are wood residues, municipal solid waste (MSW), and other non-traditional biomass resources. The project team used in-house information, detailed manufacturer databases, and past experience to identify specific supply regions, biomass fuel supply types, and biomass residue generators/sources. The analytical methodology depended upon the fuel type considered. Thus, each section in the report is split according to the type of feedstock. 1) Wood residue fuel suppliers – Data was gathered from a 2003 GIS database for Virginia wood residues developed for the Virginia Tech Department of Wood Science and Forest Products. Data for 12 counties including and surrounding the county of Fauquier was identified for analysis. The supply-shed boundary was set at 50 miles, which covered each of the 12 counties. Generally, the geometric range of the search area for a particular supply shed should not exceed an economic transport distance for a project. The transportation of biomass fuel beyond 50 miles is likely economically prohibitive, although if special circumstances presented themselves they were given consideration. The collected data included 1) County; 2) Type of manufacturer (sawmill, millwork, furniture, etc.); 3) Type of material (chips, sawdust, residues); and 4) Average material price delivered. The volume and price data was collated and used to generate weighted average fuel supple curves that show cumulative available supply quantities versus weighted average delivered prices. The curves depict the amount of fuel available in each supply region on a $/MMBtu and $/ton basis (delivered to the power plant). Finally, key wood residue generators were targeted from a database of manufacturing businesses and contacted individually to determine potential as suppliers. 2) Waste management and handling facilities – Includes MSW from landfills, industrial facilities, and transfer stations. The project team began with a database of solid waste handling facilities located in Virginia. A list was developed that shows the facilities within a 25 and 50 mile radius of Warrenton with the most potential as fuel suppliers. The key suppliers were contacted via phone to inquire about interest as being a supplier as well as to confirm volume and price data. 3) Non-Traditional biomass fuel suppliers – Includes waste tires, automotive shredder waste, and wood wastes such as right of way clearings and yard trimmings. Potential non-traditional fuel generators were identified using an in-house database of manufacturing businesses as well as contacts from past projects. These were mainly operations that generate a substantial amount of biomass waste but don’t currently have a market for the material. The project team focused on gathering data for resource availability, current use for resources, cost information, and potential for use by Warrenton. None of the contacts in the resource category were able to provide quantifiable data regarding feedstock availability. The interview results with each contact are presented below is section 5.3. Once all the relevant data was gathered, it was compiled into a spreadsheet and organized to show the suppliers with the most potential from each biomass category. ANTARES staff


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followed up on the most promising leads and conducted a focused effort to estimate total supply potential. Results An analysis of the supply data in the target region suggests that sufficient supplies of biomass are available to support the proposed bioenergy facility. There is a substantial amount of wood residues in the Fauquier area but it should be noted that there is a competitive market for these products. Prices for these materials average around $10 to $25 per ton delivered. The key suppliers listed in the interviews section should be strongly considered as sources for biomass. A feedstock requirement of 250 tons/day should be attainable through the acquisition of wood residues, MSW, or a combination of the two. Wood residues will demand a higher price, but may offer technical advantages when considered for use as a fuel. These materials are relatively high in moisture content, but they are clean and their combustion and handling characteristics are well understood. The MSW is more attractive from a fiscal standpoint because the energy project could collect a tipping fee for acquiring MSW and will save valuable landfill space. On the other hand, technical factors may make the MSW less attractive. At this point, the non-traditional feedstocks should not be counted on as a consistent supply, but may prove valuable in the future.

2.1 Preliminary Screening Prior to conducting a detailed analysis of biomass feedstocks in the Warrenton area, ANTARES has performed a more general investigation of a broad variety of feedstocks. This initial investigation aided selection of a limited number of feedstocks for a more detailed review. The preliminary screening involves estimating the availability of each feedstock based on publicly available resources, assessing the technical feasibility of the feedstocks for use as a fuel, and evaluating costs for each feedstock. The feedstocks included in the preliminary evaluation include municipal solid waste (MSW), thinnings, forest Residues, primary Mill Residues, corn stover, switchgrass, and animal manures.

2.1.1 Municipal Solid Waste Municipal solid waste (MSW) corresponds to waste from residences, businesses, and institutions. Components of MSW typically include paper, plastic, metal, glass, food, garden clippings, etc. MSW is typically collected curbside by local authorities and sent to landfills for disposal. MSW can be a good source of energy through burning it in waste-to-energy plants. MSW is burned to generate steam that can be used for heating or electricity generation. MSW is typically an abundant resource near urban and highly populated areas. To get a scale for the MSW resource in the Warrenton supply shed, ANTARES has estimated the MSW generation for each county included. This estimate is based on the assumption that each person generates approximately 1.6 tons of MSW per year1. A spatial representation of MSW generation in the supply shed is seen in Figure 3.

1 In 2004, total MSW generation for Virginia residents was 11,989,925 tons and the population was at 7,510,923. This amounts to an average of 1.6 tons of MSW per person per year.


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Figure 3. Estimated MSW Generation in Warrenton Area Supply Shed

It is unlikely that there would be any costs associated with obtaining MSW for an energy project. The majority of MSW is disposed of at landfills, costing the supplier a tipping fee ranging from around $40 to $60 per ton. An energy project could charge a $20 to $30 per ton tipping fee and have as great a supply as is available.

2.1.2 Woody Forest Biomass Thinnings Thinnings are defined as the hazardous underbrush and saplings plus fallen and/or dead trees on public and private land that can potentially be removed to implement fuel reduction and ecosystem restoration objectives. Thinnings are also referred to as “ladder fuels” because they accelerate fire’s vertical spread. Fuel treatment projects on forestlands provide a natural opportunity for biomass power or transportation fuel projects. A fuels reduction operation that extracts usable biomass will typically utilize conventional logging equipment. This includes equipment for felling, bunching/piling, extraction, processing and transport. Conventional logging equipment is not designed for the smaller material removed in a fuels reduction project, therefore costs per volume of product handling can be much higher than traditional merchantable logging operations. Processing/size reduction of the material is accomplished with a chipper, hogger, or grinder. This will reduce the material to a two-inch minus to four-inch minus chip depending on the type of equipment used. Ideally, the material would be directly loaded into a box trailer or other form of transport after size reduction to avoid any dirtying from coming in contact with the ground. Thinnings are freshly cut and will have a high moisture content ranging from 45 to 60 percent. The quantity and volume of total treatable forest biomass is collected for public and private lands as part of the Forest Inventory and Analysis National Program of the US Forest


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Service. Since biomass power and transportation fuel projects rely on low cost feedstock, the prices paid for biomass cannot compete with more traditional industry prices for merchantable timber. Therefore, the quantity of biomass available for biomass to energy projects is limited to the non-merchantable portion of thinning removals. Concerns about impacts to soil and water also limit the amount of removable thinnings available for a biomass project. It has been estimated that fuel removal projects are limited to only 85 percent of forestlands. Further, it is estimated that only 60 percent of North American forestland is accessible with conventional logging equipment. If a 30-year recovery cycle is assumed, annual supply quantities can be generated.2 Figure 4 below shows the availability of thinnings in supply shed area of the 50-mile radius surrounding Warrenton. Figure 4. Fuel Treatment Thinning Potential in Warrenton Area Supply Shed

2.1.3 Forest Residues Forest residues consist of the unutilized parts of trees leftover from logging and other land clearing operations. Traditionally, logging operations only utilize the merchantable portion of trees. The merchantable portion refers to the central stem of the tree that meets saw log or pulp wood specifications. The non-merchantable portion of the tree, including the tree top, small branches and limbs, is typically left on site in the woods since removal has not been economical for energy or other uses. The non-merchantable portion leftover from logging operations are also referred to as logging residues. The other component included as a part of forest residues is timber cut for commercial land clearing or other cultural operations such as pre-commercial thinnings or timberland clearing. This resource is typically burned on site or discarded. These residues are referred to as other residues.

2 Assumptions for potentially available thinnings calculations are from Biomass as Feedstock for a Bioenergy and Bioproducts Industry: the Technical Feasibility of a Billion-Ton Annual Supply. Prepared by the US Department of Energy and the US Department of Agriculture. April 2005.


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Extraction of forest residues for energy or other uses has traditionally been uneconomical. Rising costs of coal and other fossil fuels combined with a favorable policy environment could stimulate utilization of these products though. The US Forest Service’s Timber Products Output database tracks the total volume of roundwood products harvested from all sources in US forests. Included is data for forest residues as well. County level data is available for ‘logging residues’ and ‘other removals’ for the entire US. It has been estimated that conventional logging operations only allow for 60% to 65% of logging residues to be collected and land clearing projects only allow half of other removals to be recovered. The geographic intensity of forest residues available for collection in the Warrenton area supply shed is presented in Figure 5 below. Figure 5. Forest Residues in the Warrenton Supply Shed

Operational costs associated with obtained woody forest biomass typically involve a number of steps if bringing the resource to a central site. Figure 6 below details the different operational steps with cost estimates for obtaining thinnings and forest residues. Based on the specification of the final product, thinnings can be expected to cost $32 to $39 per ton delivered and forest residues can be expected to cost $20 to $27 per ton delivered.


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Figure 6.Operational Costs Associated with Woody Forest Biomass

Operational PhaseThinnings

($/ton as rec'd)1Forest Residues ($/ton as rec'd)2

Harvest/Residue Cost 19.15$ 6.69$

Felling 2.85$ -$

Skidding 9.61$ -$

Loading 3.52$ 3.52$

In Woods Transport 3.18$ 3.18$

Processing Cost 5.82$ 5.82$

Est. FOB Cost 24.97$ 12.51$

Transportation 7.07$ 7.07$

Delivered Cost (Unground) 32.03$ 19.58$

Grinding / Secondary Processing 7.40$ 7.40$

Delivered Cost (Ground) 39.43$ 26.98$

NOTE: All prices are operational costs. Figures do not include profit or overhead. 1 Estimates for chainsaw felling and cable skidding obtained from the article Productivity and cost of manual felling and cable skidding in central Appalachian hardwood forests in the Forest Products Journal (2004, Vol. 54). Estimates for loading, transport, and processing were calculated using the Forest Residue Transportation Costing Model (FoRTS) from the US Forest Service Forest Operations Research Unit. These estimates are based on cable loading, RO transport for in woods transport, using a tub grinder for processing, and using a 120 yd chip van for road transport.

2 Estimates for loading, transport, and processing were calculated using the Forest Residue Transportation Costing Model (FoRTS) from the US Forest Service Forest Operations Research Unit. These estimates are based on cable loading, RO transport for in woods transport, using a tub grinder for processing, and using a 120 yd chip van for road transport.

2.1.4 Manufacturing and Urban Wood Biomass Primary Mill Residues Companies that use whole logs to create primary wood products (e.g., boards, panels, veneer, beams, pulp) generate primary mill residues. Examples of such companies are sawmills, pulp and paper companies, and other millwork companies. Primary mill residues are usually in the form of bark, chips, sander dust, edgings, sawdust, or slabs. Unlike thinnings and forest residues, primary mill residues are a highly utilized resource. Existing markets include chips for pulp and paper mills, boiler fuel at industrial facilities, animal bedding for local farmers, mulch, feedstock for pellet fuels, etc. Since primary wood manufacturing mills handle very high volumes of roundwood and produce a rough product, the residues are available in large volumes at a central location. The residue size and shape is very consistent making it attractive for use in manufacturing processes and as a fuel. In addition, since these residues are a byproduct of a manufacturing process, any value gained by the mill is supplemental to primary product value. Thus, costs for primary mill residues


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are much cheaper than other woody biomass residues that solely depend on income generated by the biomass. The US Forest Service tracks annual quantities of primary mill residues in its Timber Products Output database. This data is collected every five years, most recently in 2002. The data for primary mill residues is separated into four categories: residues used for pulpwood, fuel wood, miscellaneous products, and residues not used. Overall, 41 percent of total residues went to pulpwood, 42 percent went for fuel wood, 14 percent went for miscellaneous products, and only 2 percent was not used. Total primary mill residue quantities are presented spatially in Figure 7 below. Figure 7. Primary Mill Residues in the Warrenton Area Supply Shed

Urban Wood Residues For this study, urban wood residue refers to three categories of woody biomass: woody construction & demolition (C&D) debris, woody yard trimmings, and other woody manufacturing waste. Construction and Demolition waste consists of the waste materials generated during construction, renovation, and demolition of buildings, roads, etc. The woody component of C&D waste is primarily derived from residential and commercial construction, renovation, and demolition. The four principal sources for woody yard trimmings include municipal yard waste, utility tree trimmings, private tree service companies, and various woods hauled with trash. It includes all types of wood found in residential, commercial, and institutional waste. Other woody manufacturing waste consists of the residue from non-primary wood manufacturing businesses not including construction and demolition wastes. These types of businesses include pallet manufacturers and recyclers, truss companies, wholesale and retail lumber companies, cabinet manufacturers, furniture manufacturers, etc. The majority of this resource comes from pallet and lumber companies.


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The population of a certain location most directly influences the quantity of urban wood residues generated. A recent study analyzed the relationship between population and urban wood residue generation and found the following results3: • 0.091 tons of C&D wood are generated per person per year • 0.203 tons of yard trimmings are generated per person per year • 0.039 tons of other woody manufacturing waste is generated per person per year Figure 8 below outlines the costs associated with obtaining manufacturing and urban wood residues. Mill residues are typically more expensive since the market for them can be highly competitive. Costs also depend greatly on the level of processing required. Figure 8. Prices for Manufacturing and Urban Wood Residues

Operational PhaseMill Residues ($/ton

as rec'd)1C&D Waste

($/ton as rec'd)Yard Trimmings ($/ton as rec'd)

Other Waste Wood ($/ton as rec'd)

Residue Cost 20.60$ -$ -$ -$

Processing Cost -$ 8.37$ 5.66$ 5.87$

Est. FOB Cost 20.60$ 8.37$ 5.66$ 5.87$

Transportation 7.07$ 7.07$ 7.07$ 7.07$

Delivered Cost (Unground) 27.66$ 15.43$ 12.72$ 12.93$

Grinding / Secondary Processing 7.40$ 7.40$ 7.40$ 7.40$

Delivered Cost (Ground) 35.06$ 22.83$ 20.12$ 20.33$ 1 Mill residue cost based on prices paid for residual hardwood chips in the south central US. From Wood Resource Quarterly of Wood Resources International (3rd Quarter 2005, pg. 16).

2.1.5 Corn Stover Corn stover consists of the leaves and stalks of the corn crop that is left in the field after the harvest. There are few uses for corn stover currently. Much is left on the field for soil conservation. It can be grazed for animal feed or dried and stored for fodder. Harvesting of corn stover for a biomass project would need to take place immediately after the corn harvest to avoid any weathering or degradation. The amount of stover available for removal is questionable. A recent study found that 57 percent of stover could be removed with no adverse effects to soil.4 No commercially available specialized equipment exists for stover harvesting. Initially, harvesting will rely on conventional baling equipment. Once bales of corn stover are moved to the farm gate, either they may be processed on site using a mobile grinder or hammermill or the bales may be transported to the biomass facility for storage and processing before utilization. Quantities for corn stover were derived from USDA National Agricultural Statistics Service figures for corn production in 2005. This data is available for each county in the US. Stover quantities were calculation using production data as well as a crop residue ratio and estimated moisture content: 3 Wiltsee, G. Urban Wood Waste Resource Assessment. NREL. November, 1998. 4 Corn Stover for Bioethanol – Your New Cash Crop? NREL. May 2001. http://www.nrel.gov/docs/fy01osti/29691.pdf.


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Ag Residue (dry tons/yr) = Crop Production (Bu) * Crop Residue Ratio x Dry Matter (%) / K Where: Bu = Bushels per year K = Bushel to Ton conversion or 2000 / Bushel weight in pounds. For corn, the following assumptions were made: crop residue ratio of 1.0, moisture content of 15.5%, and a bushel weight of 56 pounds.5 Figure 9 shows the calculated quantity of corn stover in the Warrenton are supply shed generated in 2005. Figure 9. Corn Stover Availability in the Warrenton Area Supply Shed

Figure 10 below details costs associated with obtaining corn stover. In this study, it is assumed that the farmer will be compensated $10 for each ton of corn stover removed from his/her land. Other operation steps involved in this cost estimation include mowing, baling, hauling to storage, stacking, storage fees, transportation to final destination, and processing. The delivered cost for baled corn stover amounts to around $53 per ton. Further processing of corn stover into a more usable form results in a final cost of around $60 per ton.

5 Residue calculations and crop assumptions based on A. Milbrandt’s A Geographic Perspective on the Current Biomass Resource Availability in the United States, prepared by the National Renewable Energy Laboratory, December 2005.


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Figure 10. Costs Associated with Obtaining Corn Stover

Corn StoverEstimated Costs($/as-rec'd ton)

Farmer's Payment for In-Field Residue 10.00Entire haying operation up to storage* 26.23

(includes cutting, baling, hauling, & stacking) Est. Rates per StepMowing or Swathing 2.55Baling 10.05Hauling from field to storage 4.37Stacking 9.26TOTAL HAYING OPERATION* 26.23

Storage** 8.00Estimated Farmgate Cost (Baled) 44.23Transportation to Plant *** 9.00Delivered Cost (Baled) 53.23Grinding* (p. 25) 6.40Delivered Cost (Ground) 59.63

Phase of Production / Delivery

2.1.6 Switchgrass ANTARES has also reviewed the potential availability and cost issues for switchgrass for the supply region considered in this study. Switchgrass is a native prairie grass, which can be fast-growing and very drought tolerant, and is an energy crop that has received considerable attention from government research programs as a potentially economic and abundant biomass feedstock that also has a wide range of environmental benefits associated with it. Figure 11 shows a county-level map of potential switchgrass availability for the supply search region considered in this study. The information on the map was obtained from the National Renewable Energy Laboratory and Oak Ridge National Laboratory, based on existing land-uses and projected county-level switchgrass yields (tons per acre per year). The potential supplies shown on the map are not existing supplies - they are the potential supplies if likely targeted lands were converted to switchgrass use if policy and economic


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conditions favored switchgrass energy crops. It is a reasonable assumption that there would be at least a several year ramp-up period for any new utility-scale switchgrass-based energy project once a supply contract is signed. This ramp-up period would be needed to enable local farmers to establish switchgrass on their lands, build up the capabilities, and supply network to deliver it as a fuel source for a large project. Figure 11. Switchgrass Potential in the Warrenton Area Supply Shed

Based on experience to date with the Chariton Valley Biomass Project in Iowa, a switchgrass supplier would need at least $40 to $45 per ton to deliver baled switchgrass to a processing facility at a local power plant. Depending on the type of facility the switchgrass might be used at, it would cost between $15 and $25 per ton (all costs included) to get it into the boiler in the proper form (to allow complete burnout, etc.). The overall cost by the time it gets to the boiler could be as high as $70/ton ($5.07/MMBtu) or as low as $50/ton ($3.62/MMBtu). In order to make a project attractive to both farmers/suppliers and the utility, the value of the switchgrass to the utility must be higher than the supplier’s cost to deliver processed switchgrass to the boiler. Incentives or renewable energy mandates/requirements will likely be needed.

2.1.7 Animal Manures Animal waste consists of cow manure, hog and pig manure potentially suitable for anaerobic digestion and poultry litter potentially suitable for combustion and gasification. Manure and litter have traditionally been utilized as fertilizer in agricultural settings to add organic materials and nutrients, such as nitrogen, to enrich soils. Poultry litter must be composted before use as a fertilizer, as fresh poultry litter is actually harmful to crop plants. Other uses for animal wastes have included fuel for cooking and even for heating in some settings. A number of factors have contributed to the increase in interest for using animal wastes for alternative applications, such as biomass. Some of these factors include disposal problems


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at confined feedlots, odor issues, unconstrained methane emissions, and other environmental concerns. Quantity estimates for animal wastes were calculated using NASS population statistics for cattle, chicken, turkeys, and hogs and pigs. The equation for calculating manure mass is described below and assumption for each animal type can be found in Figure 12. Total Solids = Populationi * TAMi * VSi Where, TAMi = Typical animal mass for animal type i (lbs/head)

VSi = Average animal volatile solids produced per unit of animal Figure 12. Average Animal Size and Annual Volatile Solids Production

Typical Animal Mass (lbs),

TAM i

Volatile Solids per Pound Animal

Mass, VS i

Cattle Beef 1,102 2.6

Milk 1,345 3.7

Other 898 2.8

Poultry Layers 3.5 4.4

Broilers 1.5 6.2

Turkeys 7.5 3.3

Hogs and Pigs Breeding 399 3.1

Other 101 3.1

Animal Type

Data Source: Milbrandt, A. A Geographic Perspective on the Current Biomass Resource Availability in the United States. NREL Technical Report NREL/TP-560-39-181. December, 2005.

Often times, animal manures are used for fertilizer or agricultural purposes. Manures contain significant amounts of nitrogen and phosphorous that assists plant growth. Costs for obtaining animal manures for an energy project should closely correspond to the fertilizer value of the manure to the farmer. This value is typically around $11 to $18 per ton. With delivery and handling, this cost increases to up to $20 to $30 per ton.

2.1.8 Preliminary Feedstock Summary A summary of quantity and cost information for each feedstock is seen below in Figure 13. MSW is the most abundant resource. Approximately 9.5 million tons of MSW are generated in counties within 50 miles of Warrenton each year. MSW is also the least expensive feedstock. It is likely that suppliers of MSW will pay $20 or more per ton to discard of the material. Drawbacks associated with MSW primarily deal with its use as a fuel/feedstock. MSW contains a wide variety in ingredients. This causes variations in energy content and


11/2/2007 16

can complicate handling and processing. Woody biomass is also abundant in the region. Approximately 2.7 million tons of woody biomass is generated each year in the supply shed. The lowest cost woody biomass would be available from wood manufacturing businesses and urban wood wastes such as C&D waste and yard trimmings. Based on the findings in this preliminary review and from discussions with Mayor Fitch, the project team has focused its effort in the detailed feedstock analysis on wood residues, MSW, and regionally available non-traditional fuels. Wood residues and MSW show technically acceptable characteristics as a feedstock, are abundantly available, and are attractively priced. Efforts investigating regionally available non-traditional fuels hope to identify residue streams such as waste tires and any other available opportunity feedstocks. The following detailed analysis characterizes each of these feedstocks within the Warrenton area supply shed. Figure 13. Preliminary Feedstock Summary Table

Feedstock Feedstock

Cost/ Benefit

MSW 9,491,403 tons/yr $20 - $30 per ton tipping fee

Forest Thinnings 426,197 dry tons/yr $32 - $39 per ton

Forest Residues 378,133 dry tons/yr $20 - $27 per ton

Mill Residues 421,628 dry tons/yr $10 - $35 per ton

Manufacturing and UrbanWood Residues 1,517,437 dry tons/yr

Tipping fee– $23 per ton

Corn Stover 456,545 dry tons/yr $53 - $60 per ton

Switchgrass Potential 130,869 dry tons/yr $50 - $70 per ton

Animal Manures 1,241,335 dry tons/yr $20 to $30 per ton

Resource Potential


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2.2 Analysis Methodology

2.2.1 Wood Residues The wood residues resource assessment task was divided into the following steps: 1) Identification of wood residue generating facilities by county; 2) Building of biomass fuel supply database; 4) Data analysis and supply curve development; and 5) Interviews with key suppliers. The fuel supply shed boundaries were established based on experience. Generally, the geometric range of the search area for a particular supply shed should not exceed an economic transport distance for a project. The ANTARES Group indicated that the transportation of biomass fuel beyond 50 miles is likely economically prohibitive. However, it was also noted by ANTARES that special opportunities often present themselves during the course of their assessments and fuel supplies outside of the starting radius were considered as identified and warranted. Using a GIS database developed for the Virginia Tech Department of Wood Science and Forest Products, the project team identified wood processing and manufacturing companies located within the search area. A total of 12 counties, including Fauquier, were identified within the 50 mile search radius and have potential as suppliers based on the wood residue generating operation taking place there. The data collected for each county included the type of manufacturer, material produced by each manufacturer, and price information. Types of manufacturers included sawmills, flooring and dimension manufacturers, paper manufacturers, housing manufacturers, millworks, cabinet manufacturers, furniture manufacturers, pallet manufacturers, and other manufacturers that produce items such as mulch and wood preservers. Materials produced included green and dry chips, green and dry sawdust, and scraps (pallets, coarse residues, mixed residues, planner shavings, sanderdust, green bark). The price information is based on Virginia averages for each type of manufacturer producing a certain type of material. Some materials produced by certain manufacturers did not report a price. In these cases, estimates were made based on prices for the same material by other manufacturers, as well as prior experience with the material (example: no price was given by housing manufacturers for dry chips, so the prices for dry chips by other manufacturers were used as an estimation). Figure 14 summarizes the location and volumes of supplies identified during the study.


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Figure 14. County-level Biomass Supply Density around Fauquier County


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2.2.2 Municipal Solid Waste ANTARE located solid waste handling facilities using a commercial solid waste facilities database. The same 50-mile radius criterion that was used for the wood residues was used for the solid waste. The complete list of solid waste facilities along with maps of their locations can be found in Appendix B. From the facilities in the given search area, the list was narrowed down based on the following steps: 1. From the 50-mile radius supply shed, 46 contacts were located from the initial search. The 46 were narrowed down to 26 based on those that had less than 200 tons. 2. Of the 26, 22 were accepted (1 is already a waste-to-energy facility, 3 were above 50 mile driving distance). Final: 50 mile radius – 22 facilities Through interviews, ANTARES learned that the most potential for solid waste suppliers lies within the counties of Rappahannock and Culpeper, which have solid waste facilities within 25 miles of Fauquier. A quantitative summary of the volumes and prices from these counties can be found in Section 5.2.

2.2.3 Non-Traditional Suppliers Potential non-traditional fuel generators were also identified using a manufacturer’s database as well as contacts from past projects. These were mainly operations that generate a substantial amount of biomass waste but do not currently have a market for the material. These generators could have potential in the future for being suppliers but currently there is not enough of a consistent supply or coordination to be relied on as a dedicated fuel supplier. See Section 4.3 for the interview results with non-traditional suppliers.


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2.3 Interview Results

2.3.1 Wood Residues • Bonnie Warton - Merrillat LP: Ms. Warton informed ANTARES that Merrillat currently

produces a large amount of wood wastes without a current market. They are disposing of 20-30 tons per day of mainly particle board, wood, skids, doors, and frames. This material is currently being taken to the Culpeper transfer station by an outside hauler who then takes it to a landfill in Richmond. Merrillat is currently working on a six sigma project to reduce the amount of waste they dispose of. They are looking at grinding the material into sawdust in order to compact it and reduce the frequency that they would have to dispose of it. She was very interested in a waste to energy project for the benefits of waste reduction and environmental sustainability.

• Vice President of Manufacturing - North American Housing Corporation: This

company manufactures modular homes at their factory in Front Royal and then delivers them to customers. They generate about 50 tons per week of wood wastes at the factory that are mainly leftover scraps from the construction process (e.g. 2x4’s, doors, plywood). They do not currently have a market for their residues. A private contractor currently picks up the wastes and delivers them to the Front Royal landfill. NAHC is interested in supplying the wastes for Warrenton’s energy plant.

• Rock Hill Lumber, Inc. – This company is a sawing and planning mill located in

Culpeper. They generate a consistent supply of 1000 tons/month of green chips at a price of $24/ton, as well as 700 tons/month of green sawdust at a price of $12.50/ton. Delivery costs run from $2.50 – $3.00 per ton. The company currently ships all residues to existing markets. Rock Hill Lumber can offer guaranteed delivery on a set schedule and can reduce prices for a steady supply in Warrenton.

2.3.2 Municipal Solid Waste • Mike Dorsey – Director of Environmental Services, Fauquier County: Mr. Dorsey

provided a wealth of insight into the Landfill operations at Fauquier. He believes the main benefit of a bioenergy plant would be the landfill space it will save by absorbing local waste. If the facility can take waste from other counties, such as Rappahannock and Culpeper, it would have plenty of fuel feedstock and will be able to collect a tipping fee. Mr. Dorsey emphasized the importance of conserving landfill space and advised against using it for anything other than waste. There is a currently a mining operation planned to remove wood waste from a C&D cell. The wood could be used by the biomass facility, but there is a limited supply.

• John McCarthy – County Administrator, Rappahannock County: Rappahannock

County is located directly west of Fauquier. It has its own landfill, which will be closing in September or October of 2007. The landfill takes in 20 tons/day of almost exclusively MSW and very little C&D. The tipping fee is $43. After the landfill closes, Rappahannock will take its waste to the Culpeper County transfer station, which is 25 miles away. The tipping fee there is $39. Culpeper has its own landfill, which will be closing soon as well. Allied Waste down to Richmond will take the waste. McCarthy stated that he would be


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very willing to take Rappahannock’s waste to Warrenton, which is only 14 miles away, instead of Culpeper. He is also supportive of a waste-to-energy project and preserving landfill space, wherever it may be.

• Paul Howard – Director of Environmental Services, Culpeper County: Culpeper

County is located south of Fauquier. The Culpeper landfill closed in 1998. Their waste is currently being taken to the Culpeper transfer station, which then transports it to Richmond. Culpeper generates 300 tons/day of MSW. They are under long term contracts with the waste haulers but are able to get out of them. Mr. Howard stated that he would certainly be willing to transport the waste to Warrenton if the economics proved favorable.

2.3.3 Non-Traditional These contacts provided insight into resources that are not currently considered sources of fuel for energy operations. The materials are usually waste products that are not quantified. Although there is no hard data available for these resources, these contacts could prove valuable as the first step in organizing and coordinating waste materials as a source of energy production. • Glen McMillan - Virginia Department of Transportation: Mr. McMillan said that

VDOT activities such as construction projects, small maintenance, and sub-division development generate a large amount of wood waste. This waste is generally in the form of wood chips, shrubbery, and tree thinnings. The problem is that the supply of these materials is very volatile. The operations that produce the biomass are sporadic and do not provide a reliable flow of material. There is also the problem of storage, which does not currently exist. Although a large amount of waste is generated, there is not enough of a dependable supply to be considered as a fuel source for a power plant. Mr. McMillan does believe that there will be more organization in the future, and if the waste could be better coordinated VDOT would be interested in supplying a waste to energy facility.

• Shawn Davis – Virginia Department of Environmental Quality: Mr. Davis provided a great overall status report for biomass in the state of Virginia. He was not aware of the new waste to energy plant proposed in Warrenton, but said there is one in the Tidewater region, one in Arlington, and one off I-95. A large source of residue biomass in the state comes from clearings. These could be created by the utility companies for running their lines, water & sewer companies for their pipes, pipeline companies, and privately produced biomass from leaves and yard clippings. There is currently a sawdust explosion going on in southwest Virginia with all the new construction and development. There is only one CDD landfill there and it cannot handle all the waste. In the Shenandoah Valley, there is also a lot of leftover debris with nowhere to put it. As a result, it is being burned. Mr. Davis believes they waste generators would probably like to give it to someone else for disposal. One source that may have large potential as a biomass supplier is the Department of Emergency Response and in particular, the hurricane response team. After natural disasters, there is always an enormous amount of leftover biomass that has no use. There is a list of outlets that may take it and often have pre-permitting sites for debris. In fact, there is probably still stored debris left over from the last hurricane season.


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• Martin Ogle – Fairfax Regional Park Authority: Mr. Ogle was referred by Charlie Becker of the Virginia Department of Forestry. He has expressed some interest to Mr. Becker about waste to energy power plants but only works within one park, which doesn’t produce a large amount of biomass. After talking, however, it appeared that there might be some potential from his operations. There is a large problem at the parks with non-native vines growing everywhere and taking over. They are trying to keep them at bay and currently just leave the remains. As this problem becomes more of an issue (as it is expected to be) there needs to be an outlet for the cut down material. Another possible fuel source is hazardous trees. These are trees that are at risk of falling and pose at threat because of their proximity to power lines and houses. The park authority is hoping to instill a timber management program where they could cut down the trees and find a market for them. They were looking at giving them to local sawmills, but Mr. Ogle opened up to the possibility to send the material to a waste to energy plant. He should be considered as a potential supplier should the project commence.

• Allan Lassiter - Virginia Department of Environmental Quality: Mr. Lassiter is a member of the DEQ’s Waste Tire Management Staff. He said that for the purposes of a feasibility study, to estimate the waste tire generation figure one tire per person per year. The tires themselves are 20 lbs. apiece. There is currently a reimbursement program in Virginia for waste tires. A $1/tire tax is imposed on all new tire sales at a retail outlet. The $1 is passed along to end users as a subsidy for each tire they dispose of. The majority of end uses are for civil engineering project, tire derived fuel, and recycling projects. This amount is in addition to a tip fee received by the end user, which is typically $50-$100 per ton. Mr. Lassiter informed ANTARES that tire piles cannot be counted on as a fuel supply. There are currently only 2 million tires remaining in piles and those will be gone very soon. For a fuel supply, only the daily generation can be considered. Mr. Lassiter believes procuring a supply from the main waste tire generators (retail tire dealers, auto shops) would be very difficult because they are all under long term contracts. The only place tires may be able to be obtained would be from landfills that receive tires from small generators in the local area. Mr. Lassiter was not sure of the amount generated in the Fauquier area but advised using the 1 tire/person/year figure for estimation.

• Mr. Rait – Fairfax County I-95 Landfill Operator: Mr. Rait was contacted to

determine the potential for diverting their waste tires to the town of Warrenton for use as a fuel feedstock. Fairfax currently brings in 700-800 tons/month of used tires. Almost all of these are from companies that are under contract. The tipping fee is $75/ton paid to the landfill. The landfill then pays the landfill operator $60/ton to dispose of the tires. They are usually shred up and used to cover trash or for drainage. The contactor, being the end user of the tires, also receives the $22.50/ton subsidy for the Virginia government. After other costs are included, Fairfax just about breaks even. The landfill also has a waste-energy plant, which currently burns 3,000 tons/day of MSW. It does not burn the tires because the landfill space that burning the MSW saves is more valuable then burning tires that have a high BTU value and would thus cause more MSW to be landfilled. Mr. Rait informed ANTARES that they would be interested in taking their tires to Warrenton and a deal could be worked out to pass on a tipping fee similar to what the landfill operator is paid.


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• Hafez Al-Haj – Prince William County Landfill Operator: Mr. Al-Haj was

questioned about the waste tire situation in Prince William County. The county currently receives around 2,000 tons/year of waste tires. The tipping fee is $60/ton and is usually paid through contracts with companies such as repair shops. The tires are then sent to a scrap metal contractor who shreds the tires along with other silt and fluff. The material is then sent back to the landfill to be used for cover. They did not have an estimate of what exactly is paid to the contractor because it is part of a packaged contract involving other materials in addition to the tires. Mr. Al-Haj informed ANTARES that they are very satisfied with their current operations but if the economics worked out there could be potential to send the tires to Warrenton.


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2.4 Data Analysis

2.4.1 Wood Residues Supply Cost Curves Supply cost curves were produced to show cumulative available supply quantities versus weighted average delivered prices. A weighted average cost takes into account multiple contracts from multiple suppliers and is typically a good indicator of overall project fuel costs. The weighted average cost should be read as “13,500 tons of material per month may be available at an average cost of $13/ton.” Supply curves were generated for the supply region surrounding the county of Fauquier. These curves present the $/ton and $/MMBtu weighted average delivered cost versus available supply of biomass in tons/month and MMBtu/month (see Figure 16, Figure 17, and Figure 18). The prices from the 2003 Virginia Tech study have been put in 2007 dollars. Average heating values drawn from the ANTARES in-house resources were used to convert monthly tonnages and prices into heat based pricing units and volumes. The conversion factors accounted for differences in biomass composition and moisture content. A summary of fuel characteristics for various biomass fuels can be found in Appendix A. In order to provide perspective on the cost figures included in the database obtained from Virginia Tech, Antares obtained recent chip price figures from Timber Mart-South, a forest products reporting agency associated with the University of Georgia. A summary of price info is seen in Figure 15. The prices for hardwoods are plotted in Figure 16 for a comparison against the supply curves. The Timber Mart-South prices are in 2007 dollars and are comparable with the prices taken from the Virginia Tech database. Figure 15. Summary of Relevant Chip Prices

Low High Average Low High AverageSawmill 16.16$ 22.00$ 19.08$ 15.66$ 22.75$ 19.21$ Chipmill 26.00$ 35.00$ 30.50$ 26.00$ 34.00$ 30.00$

Chipmill 9.88$ 19.25$ 14.57$ 12.33$ 19.00$ 15.67$

Pulp Chips

Fuel Chips

Softwood Hardwood$/Ton


11/2/2007 25

Figure 16. Supply Curve for Potentially Available Biomass

Weighted Average Delivered Cost vs. Quantity Counties within 50 miles of Fauquier

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

Tons per Month

$ pe

r Ton

ChipsSawdustScrapsCumulativeAverage Fuel Chip Price*Average Pulp Chip Price - Sawmill**Average Pulp Chip Price - Chipmill***

Note: All average prices include $4.50/ton for delivery. *Reported by Timber Mart-South (TMS) for Georgia Hardwoods. Virginia fuel chip prices are not available from TMS. **Reported by Timber Mart-South for Virginia Hardwoods. *** Reported by Timber Mart-South for Virginia Hardwoods.


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Figure 17. Supply Curve for Potentially Available Biomass

Weighted Average Delivered Cost vs. Quantity Counties within 50 miles of Fauquier

0.00

0.50

1.00

1.50

2.00

2.50

0 10,000 20,000 30,000 40,000 50,000

Tons per Month

$ pe

r MM

Btu

ChipsSawdustScrapsCumulative

Figure 18. Supply Curve for Potentially Available Biomass Weighted Average Delivered Cost vs. Quantity

Counties within 50 miles of Fauquier

0.00

0.50

1.00

1.50

2.00

2.50

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000

MMBtu per Month

$ pe

r MM

Btu

ChipsSawdustScrapsCumulative


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2.4.2 Municipal Solid Waste To support a project relying on MSW for power generation, Warrenton will have to rely on waste from outside counties. The neighboring counties of Rappahannock and Culpeper hold the most potential as suppliers. They generate a steady supply of waste that would be more than enough to support a power generating operation. In addition, these counties could save on transportation costs and tipping fees by diverting their waste to the Warrenton landfill. A summary of volumes and prices for the counties of Fauquier, Rappahannock, and Culpeper is provided below in Figure 19. Figure 19. County Wide MSW Generation

County Average tons/day Tip fee ($/ton)Fauqueir landfill 225 45.00$ Rappahannock landfill 20 43.00$ Culpeper transfer station 300 48.00$ Total 545 46.60$ 2

2 Weighted Average

MSW Generation1

1Note that these numbers are based on the assumption that 100% of the MSW will be used in the biomass-energy facility. If some materials are to be sorted out, the daily tonnage available for energy production must be adjusted accordingly. Refer to the MSW breakdown for percentages of materials.

Figure 20. Total Daily Tonnage MSW from Fauquier, Rappahannock, and Culpeper County with Potential for Energy Production

Metal, 41.5

Rubber, leather, textiles,

39.8

Wood, 31.1

Food Scraps, 64.9

Plastics, 64.4

Yard Trimmings,

71.5

Paper, 186.6

Breakdown of MSW1

Paper 34.2%Yard Trimmings 13.1%Food Scraps 11.9%Plastics 11.8%Metal 7.6%Rubber, leather, textiles 7.3%Wood 5.7%Glass 5.2%

Other 3%1Based on national averages from the EPA website


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As learned from John McCarthy, the Rappahannock County Administrator, Rappahannock County would be willing to divert their waste to the Warrenton Landfill for the waste-to-energy facility. The county’s landfill will be closing in September or October because of a lack of capacity. They will then ship their waste to the Culpeper County transfer station, located 21 miles away. They would much rather send their waste to Warrenton, which is only 14 miles away to save on transportation costs. Maps of the planned route to Culpeper and the alternative route to Warrenton are shown in Figure 21 and Figure 22 below. Figure 21. Map of the route from Rappahannock County landfill, located in Amissville Virginia, to Culpeper County landfill, located in Culpeper Virginia. Distance – 21 miles.


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Figure 22. Map of the route from Rappahannock County landfill, located in Amissville Virginia, to Fauquier County landfill, located in Warrenton Virginia. Distance – 14 miles.


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2.5 Fuel Supply Study Conclusions & Recommendations Based on the initial results obtained by the project team, there appears to be a more than adequate supply for the proposed biomass facility, which plans on operating at 250 tons/day and then scaling up. A summary of the major considered feedstocks is presented in Figure 23 below. It is important to note that the majority of wood residues and waste tires may be unavailable for use because they already have markets, and in the case of waste tires are likely tied up under long-term contracts. Mike Dorsey from Fauquier County estimates that their landfill presently receives 218 tons/year of tires. When a similar landfill factor is applied to the MSW volume from the Culpeper transfer station, the result is an estimated annual quantity of 296 tons/year of tires. Therefore, although the current annual waste generation of tires in the Fauquier area could be approximated at 20,170 tons/year (the 12 counties surrounding Fauquier studied in this report), the tire volume available directly from local landfills could be only 514 tons/year under current conditions. The most potential is in the MSW currently going into the Fauquier and Rappahannock landfills plus the Culpeper transfer station. From these three facilities, up to 545 tons of MSW per day could be made available for an energy project. This scenario is advantageous for nearby counties since tipping fees will be lower and since the Fauquier site requires shorter hauling distances. Figure 23 also presents the amount of heat available from each of the tabulated feedstocks and, using a very conservative heat rate for conversion to electricity, the maximum amount of power that could be produced if all of the identified feedstock quantities were converted to electricity. Since the proposed project is targeted to provide electricity in the 5 to 10 MW range, there appears to be the potential for more than enough feedstock to support a project at that scale if economics are favorable for the energy conversion process. Figure 23. Feedstock Summary Table

FeedstockQuantity

(tons/month)Energy Value

(MMBtu/month)Ave. Feedstock

Price ($/ton)

Avg. Feedstock Price

($/MMBtu)

Typical Heat Rate(Btu/kWh)

Est. Capacity Factor

Max Plant Size

(MWe)

Wood Residues 40,420 391,833 $18.80 $1.94 20,000 80% 33.5

MSW1 16,350 166,770 ($13.00) ($1.27) 20,000 80% 14.3

Waste Tires2 1,681 57,060 ($100) ($2.95) 20,000 80% 4.91The $13/ton is the avoided cost of paying a contracor to bury the MSW (currently $1 million per year for 75,000 tons of MSW).2Assumes one tire per person will be available from Fauquier County and the residents of 12 surrounding counties. A heating value of 39,480 kJ/kg was used for waste tires (from Phyllis online database). Also, the average feedstock price for tires takes into account the tire reimbursement program in Virginia provides $1 per re-used tire. This figure does not include a tipping fee which typically ranges between $50-$100 per ton.


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Figure 24. C&D Summary from Fauquier County

tons/year1 Tip fee($/ton)2

40,000 $46.00

2The $46/ton is the tipping fee presently received at the landfill. That tipping fee could be reduced to $20/ton for the energy facility.

Anticipated C&D Wood Generated from Fauquier Landfill

1Antares will also obtain estimates of the proposed mining operation to recover wood from the existing C&D cell at the Fauquier landfill. However, this would not be considered a long term, sustained supply because it will run out when the mining operation is completed.


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3 Legal, Permitting and Regulatory Issues

An integrated bio-refinery producing electricity and bio-fuel involves special considerations in addition to those issues typically encountered in the permitting and licensing of energy facilities. First, the nature of the project, which consists of a unique configuration of new but proven “green” gasification technology with technology still in development, does not fall tidily within the definitions and concepts of existing permit language. Usual regulatory interpretation is that, if a thing is not specifically allowed, then it is deemed prohibited.6 Presentation of innovative technology faces both a learning curve and a credibility challenge in addition to ordinary permit issues. Since this project is a “first of its kind” and potential template for subsequent users means that the project must also accept and anticipate concomitant disconnects with existing permit and licensing processes. Second, Fauquier County itself presents a mix of problems for approval of any energy related project. Geographically, the county is on the Virginia Piedmont located about 40 miles south and west of the Washington, D.C., metroplex.7 All runoff and some groundwater eventually affect the Chesapeake Bay, critical waters already the subject of stringent federal and State regulations, multiyear planning and designated high dollar actions to prevent and counter present or future pollution. 8 Water quality is carefully monitored.9 Likewise, due to prevailing weather conditions and increasing population and transportation growth in Northern Virginia, there are air quality problems. Fauquier County’s ambient air quality is subject to monitoring and all activities which contribute to air pollution are subject to conditions defined by the federal Clean Air Act and Virginia law and regulations.10 Further, any activity that might adversely affect air quality is a matter of intense concern to the National Park Service of the U.S. Department of the Interior. Shenandoah National Park with its scenic Skyline Drive lies directly west of the County. Visibility from the Park as well as health of the Park ecosystem is already impaired, and any potential for further degradation

6 E.g., Fauquier County Zoning Ordinance, Article 2-301, www.fauquiercounty.gov/government/departments/commdev/index.cfm?action=zoningordinance1. 7 Fauquier County Government Home Page, www.fauquiercounty.gov/government. 8 Federal Water Pollution Control Act (Clean Water Act), 33U.S.C. §§ 1251-1376, See especially 33 U.S.C. § 1267 et seq. 9 Virginia Water Quality Improvement Act of 1997, Va. Code § § 10.1-2117-2134; Chesapeake Bay Preservation Act, Va. Code § 10.1-2100. 10 Clean Air Act, 42 U.S.C. § 7401 et seq. (1970), Va. Code . § § 10.1-1300 et seq., 9 VAC 5-20-200. Fauquier County is bounded by Counties, Loudoun to the north and Prince William to the east. Both of which have been determined to be Nonattainment Areas requiring special protection under federal and State regulations for Ambient Air Quality. Thus far, Fauquier County air quality has not exceeded limits set by the National Ambient Air Quality Standards and retains status as a “prevention of significant deterioration are” (PSD). However, future readings may reveal sufficient exceedences to affect its status. Interview, Terry H. Darton, Environmental Engineer Consultant, and K. Dean Gossett, Environmental Engineer Senior, Department of Environmental Quality, Fredericksburg, June 20, 2007. Air pollution sources in any PSD are regulated by defined “Classes” to maintain air quality as new businesses develop. Permits and emission control requirements vary by the classification, with the most strict being Class I, which are primarily national parks and wilderness areas; Shenandoah National Park and the James River Face Wilderness Area are Class I areas. Class I areas may require controls of nearby industrial development. Class II, which includes Fauquier County, allows only limited amounts of new emissions and requires a showing of specific technological levels (“Best Available Control Technology” or BACT) by any facility seeking a permit. www.deq.state.va.us/air/permitting/xcaa.


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would trigger both state and federal responses.11 Both George Washington and Jefferson National Forests and the James River Face Wilderness Area could also be affected by a decrease in air quality in Fauquier County, thereby also involving the U.S. Department of Agriculture’s National Forest Service. The entire County is a nationally significant historic area.12 The historic character of the region has made tourism is a major economic factor for Fauquier County.13 A real or perceived adverse impact on scenery, open space, the many historic homes and buildings, Revolutionary and Civil War battlegrounds, or other archaeological sites inevitably engenders intense scrutiny by a number of vigilant and aggressive organizations, which have had no hesitation in raising legal and public opinion challenges to actions deemed a threat to Fauquier County heritage14.

3.1 Preliminary Actions for the Integrated Bio-refinery Project and Results

3.1.1 Public Opinion Success for the proposed integrated bio-refinery depends upon economic and environmental concerns being foreseen and dealt with sensitively. The practical considerations associated with routine permitting and regulatory requirements are compounded by a need to inform and persuade an intensely interested and often far from credulous public. The Mayor and the Town of Warrenton recognized the historic and environmental concerns presented by the concept of building any electric generation or fuel refinery in Fauquier County, albeit a “green” one. Steps were taken early to involve the public in organizing and planning the project.15 Private citizens have been the driving force for the project since the Mayor and Town Council of Warrenton made the first public overtures for the Green

11 www.shenandoah.national-park.com/nat.htm#air; www2.nature.nps.gov/air/Permits/ARIS/shen;National Parks Conservation Association, www.npca.org/stateoftheparks/shenandoah. 12“Fauquier County,” Journey Through Hallowed Ground, www.hallowedground.org., See also, www.pecva.org, the website for Piedmont Environmental Council: www.mosbyheritagearea.org, website for Mosby Heritage Area Association. 13 www.fauquiercounty.gov/government/departments/econdev. . 14 The coalition of citizens opposed to the construction of a “theme park” by the Disney organization resulted in international publicity and years of public relations and legal confrontations led by the Piedmont Environmental Council; Disney lost. Similarly, local activists have rallied to oppose any enlargement of existing power transmission corridors by Dominion and Allegheny Power companies. This controversy also has achieved national status, involving legislative proposals in the United States Congress supported by Virginia and New York, New Jersey and Pennsylvania Representatives, and could be expected to last years until resolution. Electric power generation is a particularly hot topic in the locale. See, “We’re With You – PEC Pledges To Help Southern Fauquier Defeat ‘Preferred’ Power-line Route,” Fauquier Times-Democrat, March 7, 2007, A1; “Southern Fauquier Signs On In Fight Against Power Line,” Fauquier Times-Democrat, April 4, 2007, A1; www.pecva.org. 15 Several public meetings of interested persons have been held including an initial March 15, 2007, briefing by personnel from the Idaho National Laboratories and from Antares Group, an USEPA Partner listed consulting firm, concerning technology potentials followed by a general discussion of availability and costs of possible feedstock sources. On April 10, 2007, a forum of interested citizens convened in the Warrenton City Hall and volunteered to research and work in various areas to support the Initiative. This citizen based approach comports with the recommendations and guidelines published by the Rocky Mountain Institute for successfully developing local economies and improving communities using renewable energy technologies. See, www.rmi.org.


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Initiative by submitting an application for a funding grant from the United States Department of Agriculture Rural Development office.16 A volunteer citizen group, the Green Initiative Committee, is chaired by the Mayor. The Committee has undertaken preliminary actions including outreach to citizens as well as to concerned groups, including the formidable Piedmont Environmental Council. Committee members have publicized the concept and have made efforts to meet, inform and include other citizens in the Green Initiative. To date, this approach has worked. No local citizen opposition is known to exist to the Green Initiative’s proposal to use County waste to produce electricity and develop bio-fuel.17

3.1.2 Politics and Government In advance of a formal feasibility study, the Green Initiative Committee under the leadership of Mayor Fitch began exploratory contacts with federal, State and local agencies that may be involved in funding or approving or issuing permits for planning, building, construction, and operation of the proposed project. Likewise, preliminary contacts have been made with County politicians and public employees and offices that will be essential to successful implementation of the proposed project. Fauquier County is organized under the County Administrator form of government pursuant to Virginia law. A professional public employee, the County Administrator, is appointed by the Board of County Supervisors. Fauquier County has five elected County Supervisors, each of whom represents a political subdivision entitled a Magisterial District. Any official action requires the positive assent of the Board of Supervisors, or at least three of the five.18 2007 is an election year, and, while it is known that two of the five seats are not contested, three are. The election of the final Board will not be until November, 2007. Therefore, County participation in the Green Initiative depends upon the Board of Supervisors as constituted after November 2007. Contact has been made by citizens with candidates for election to inform those persons about the Committee, the nature of the proposed integrated bio-refinery project, and offering access to the project and process. This proactive and transparent approach seems to work. No Supervisor or candidate is known to oppose the concept,19 and several have expressed positive reactions. It may be assumed that when the appropriate time comes for official County action, support will be forthcoming from the elected officials.

16OMB Circular A-102, SF 424 (Rev 9-2000), Application for Federal Assistance from United States Department of Agriculture Rural Development, dated January 20, 2007; Minutes of the Regular Meeting of the Council of the Town of Warrenton Held on January 9, 2007, New Business. USDA Rural Development grant application filed January 30, 2007. The project was approved for funding, and budget funds in the amount of $45,000 were released and delivered to the Town on May 30, 2007, to be used to study the feasibility of the proposed facility. The Town of Warrenton by unanimous vote of its Council January 9, 2007, approved $5,000 in 10% matching funds for the USDA grant funding. 17“Mayor Wants Warrenton to ‘Go Green’, “Fauquier Times-Democrat, February 7,2007, A1; “Trash-to-Gas Dream Is Landfill Reality,” Fauquier Times-Democrat, February 28, 2007, A1; “Grand-thinking Warrenton Mayor Wants Ethanol Plant,” Washington Post, March 12, 2007, B01; “One Man’s Trash is Another’s Bio-Mass,” Jim Bacon, Bacon’s Rebellion, The Forum, Fauquier Times-Democrat, March 14, 2007, A21. The Mayor on February 1 testified before the Senate Committee on Energy and Natural Resources on locally based production of renewable energy, has given interviews to National Public Radio (broadcast March 12, 2007) and the British Broadcasting Service, and has made numerous public appearances to discuss the topic of producing both electric and alternative fuel from municipal and construction waste (for example, Mayor George Fitch –“ Opening Remarks – A Vision for the Region,” A Bioenergy Research Symposium, May 30, 2007, Middleburg, Virginia, sponsors: Virginia Polytechnic and State University and Virginia Cooperative Extension Service). 18 Fauquier County Government Home Page, www.fauquiercounty.gov/government. 19 Interview, June 4, 2007, Paul McCulla, Fauquier County Administrator.


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County employees and agencies have received preliminary contacts as well, and all have reacted favorably to the concept. Meetings and briefings are being arranged for County Planning and Zoning staff members as well as for appointed Planning Board members. It is anticipated that these discussions will proceed and be mutually informing as the project for the integrated bio-refinery goes forward.20 In the light of the above background, the following legal, permit, license, and regulatory issues have been identified, described, and likely time constraints set out.

3.2 Local Issues

3.2.1 Site Selection and Uses, Location and Zoning Location and construction of the proposed facility must comply with local Planning and Zoning provisions.21 No structure may be built, nor may any use be made of land in Fauquier County except in compliance with the county ordinances.22 Zoning applications, interpretation and enforcement are administered by County professional staff. Realistically, staff advises that, while the process can take considerably longer, a properly executed and filed application for site plan approval should take 120 to 180 days, and may be conditioned upon receipt of any necessary state or federal environmental or operational permits. However, staff also advises that the site plan approval planning process may occur concurrently with other permit applications and approval processes.23 Requested variances, special exceptions to permits or zoning changes must be submitted to the County Planning Commission, consisting of five members, one appointed by each Supervisor for his or her District. Decisions of the Commission are subject to review by an appointed Board of Appeals with final administrative action by the Board of Supervisors. Changes to the Zoning Ordinance must be initiated either by professional staff or suggested by a Supervisor, and in every case the proposed change must follow a precise and exacting review and approval process. Again, staff advises that, absent emergency and without complications, zoning changes usually take 120-180 days.24 Fauquier County currently operates a waste landfill site.25 The landfill has been in existence for many years, and is presently owned and operated by the County in two parcels which are subject to two state issued waste management permits.26 These two parcels comprise five “cells” located on approximately 218 acres situated just off U.S. Highway 29 on the

20 Ibid.; electronic communication from County Administrator Paul McCulla,, [email protected], June 18, 2007, 9:57:46 AM EDT. 21 Fauquier County Zoning Ordinance, Article 2, Part 1, 2-102, www.fauquiercounty.gov/Government/departments/commdev/index.cfm?action=zoningordinance. 22 Ibid., 2-101, 102 23 Interview, June 4, 2007, Melissa Dargis, Assistant Chief of Planning, Planning Division, Department of Community Development, Fauquier County; Interview, June 4, 2007,Charles W. (Wally) Horton IV, AICP, Senior Planner: Zoning, Permitting & Inspections, Department of Community Development, Fauquier County. 24Interview, Dargis, Ibid. 25 See, attached maps, Ex.1 & 2. 26 Virginia Department of Environmental Quality, Office of Waste, Permit 575 (September 23, 1994); Virginia Department of Health, Bureau of Solid Waste & Vector Control, Permit 149 (February 4, 1974) (Note: this permit is now administered by the Department of Environmental Quality, Office of Waste).


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southeast border of the Town of Warrenton. The area is zoned RA, although a portion of a 50-acre parcel zoned R1 overlies the headquarters office area in the north end of the site.27 A subdivision and the Warrenton campus of Lord Fairfax Community College occupy the tract northwest of the landfill, occupying the old farmstead from which part of the landfill was carved many years ago.28 There are outlying waste transfer sites throughout the County where household waste may be deposited and some recycling occurs, but all non-recyclable and most waste eventually is transported to the existing landfill. Landfill access is now via a major highway intersection connection. The landfill itself operates pursuant to a Special Exception to the Zoning Regulations.29 A large electric power transmission line, which is part of the Mid-Atlantic power grid known as the PJM Interconnection, LLC,30 crosses the eastern border of the present landfill site. Depending upon the technology selected, the proposed integrated bio-refinery could utilize daily waste transported to the landfill site for feedstock, could use waste materials “mined” from old, closed landfill cells, or could combine both streams as feedstock for its process as well as being able to accommodate special wastes such as used tires or bio-mass specially transported to the site as feedstock. In addition, the County has recently purchased another approximately 197 acre tract to the north of the landfill.31 Planning of the uses of this new acreage has not been finalized; but, it is anticipated that landfill operations will participate in some aspects of that acreage if only for vehicle parking and uses associated with mining necessary soil for waste coverage.32 This tract is roughly bisected by the electric transmission line mentioned above. The geographical attributes and physical location of the landfill predispose site selection for the proposed biorefinery project.33 In view of the sensitive nature of the entire area and the existing conditions, placing the proposed facility anywhere but on the County landfill site or on adjacent land parcels seems impractical.

27 RA indicates that the land is “Rural Agricultural,” a status that indicates that the area is and is intended to protect agricultural uses. “R1” zoning indicates that the land is in a Residential District and has been assigned a density of one unit per acre. Fauquier County Zoning Ordinance, Article 3, Part 1, 3-100. 28 Map. Ex. 1, n. 20 supra. 29 Note: The landfill special exception is listed pursuant to 3-311.13 of Category 11 (Public and Quasi-public Uses), Chapter 3, Planning and Zoning Ordinance. However, Chapter 3’s Category 20 (Public Utilities) 3-320.5 provides a special exception designation precisely for electric generation facilities. It is unclear why this category was not selected for the methane to electricity facility, and it might be the better choice for a second facility on site. Staff advised that they will review the files and provide additional guidance in advance of any actual application being filed on behalf of the Green Initiative project, and the County Administrator recommends this procedure. The County Administrator advises that no County permit was issued at the time of construction of the plant to convert methane to electricity because at that time it was theorized that “the County was already disposing of the methane by one method (flaring it off) and that the conversion of the methane to electricity was just another method of disposal.” The current administration is not confident that the same analogy would apply to a bio-fuel refinery and will wish to discuss that matter when and as technology is selected. Communication, McCulla, n. 15 supra. 30 Interstate electric transmission lines such as the Mid-Atlantic grid are regulated and administered by the Federal Energy Regulatory Commission (FERC). See, http://www.pepcoholdings.com/about/ferc. 31 See, Map, Ex. 1 supra. 32 Interview, June 1, 2007, Fauquier County Director of Environmental Services and Landfill Manager Mike Dorsey. 33 For example, the proximity of the college campus, classified as a “school” under existing pertinent regulations dealing with waste regulation, could potentially bar a “new” landfill operation, but the operations and permitted activities of the present site grandfather similar activities on site.


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3.2.2 Facility Construction Actual construction of the proposed integrated bio-refinery facility would be subject to the County Code requirements as administered by County professional staff. Assuming that the basic architectural designs and elevations are completed and submitted for site plan approval and there is appropriate management of the construction contractors, no issues except basic inspections and approvals performed in seriatim for ordinary commercial construction should be anticipated. Construction cannot begin until and unless site approval has been obtained and zoning approved.34 Actual construction time will depend upon facility design. It should be noted that all County approval processes can, and indeed must, be coincident with State permitting actions since part of the permitting process related to pollution control requires that proof be presented that there has been a local governmental certification (LGOF) before a State permit is issued.35

3.2.3 Local Issues: Preliminary Actions, Results and Conclusions Should a change in the Zoning Ordinance itself be required to authorize location of the bio-refinery, that process must be initiated as already noted by either staff or a Supervisor. The process can be time consuming but should be expected to take a minimum of 120 – 180 days. During interviews with staff concerning interpretation of the Zoning Ordinance’s provisions, staff commented that there may already be a need for some updating in the light of increased interest in and uses of alternative energy throughout the County. Staff volunteered to examine the existing county ordinances and zoning provisions and to confer with the Green Initiative Committee and other interested persons about what, if any, zoning language considerations or legal interpretations might be required.36 The present County Administrator, who is the former County Attorney, has advised that he recommends that the proponents of the proposed integrated bio-refinery work with County professional staff and seek specific approval of the whole project ab initio rather than using the example of the small, existing methane gas fueled electric generation facility.37 The fact that County staff has already expressed a need to address the problems with current language and seem interested in facilitating coordination of the application process may indicate that the lower 120-180 day time frame, rather than a much longer delay, would be applicable to an application for approval of the integrated bio-refinery facility. In any event, no one among staff expressed any indications that a properly completed and submitted application could not be approved, merely that it might take a bit more work on their part. Discussion and negotiations are currently underway to attempt to resolve the legal issues presented by the existing Contract pertaining to gas use and site occupancy and access. No outcome or time frame can be projected at this time.

34 Fauquier County Zoning Ordinance, Article 2, §§ 2-101, 2-102. 35 Interview, Darton and Gossett, June 20, 2007, n. 5 supra. LGOF certification may be shown by a local government representative signing an acknowledgment or by permittee presenting DEQ with “return receipt” documentation of mailing and receipt of the notice; if no local governmental official objects to the process, a DEQ permit may be issued within 45 days for an otherwise proper and complete application for an air permit. 36 Interview, Horton, n. 17, supra. 37 Communication. Paul McCulla, n. 15 supra.


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3.3 Federal Regulatory Programs and Permits Construction and operation, as well as the effects of operations, of both electric generation and refinery facilities are governed by federal statutes.38 The provisions of most of those statutes are environmental and public health matters under the aegis of the United States Environmental Protection Agency; however, certain provisions related to energy development and electric transmission fall under the purview of the United States Department of Energy and the Federal Energy Regulatory Commission.39 In addition, as already noted, other federal Departments may be affected by the proposal, such as the Departments of Interior and Agriculture because of potential impacts upon the National Park, the Chesapeake Bay, or National Forests. Further, also as noted, development of the proposal has already benefited from a federal grant and other grant funds may be involved in finalizing the project. In each instance, as applicable, these federal concerns will need to be addressed in a timely and effective fashion.

3.3.1 US Environmental Protection Agency and NEPA Provisions The pertinent air quality and emissions, waste, water and pollution control permitting and enforcement programs have been delegated to the Commonwealth of Virginia as administered by the Commonwealth’s Department of Environmental Quality.40 However, the requirement that environmental effects form a part of the decisional process for any significant action undertaken by a federal agency or any federally funded program will underlie the entire proposed integrated bio-refinery process.41 As early as possible within the process, determinations must be made concerning any need to draft and finalize of environmental documents such as a finding of no significant impact or an Environmental Assessment or Environmental Impact Statement if there is to be utilization of federal grant monies or other federal involvement in building or funding the project.

3.3.2 Federal Energy Regulatory Commission/ Department of Energy It is unlikely, due to the estimated size and capacity of the proposed project, that the proposed electric generation unit and any power transmissions or sales of capacity would require direct action by the Federal Energy Regulatory Commission since the projected generation would range between 5 and 12 megawatts, depending upon the technology selected. However, since this proposal is intended, if successful, as a potential model for replication by other localities, there may be interest on the part of FERC based upon the role such small generators en masse might play in overall energy security or interstate transmission grid stability. Under existing federal law and regulations, access to the

38 Safe Drinking Water Act, 42 U.S.C. § 301f et seq.; Federal Water Pollution Control Act, 33 U.S.C. §§ 1251-1376; Clean Air Act, 42 U.S.C. § 7401 et seq.; Solid Waste Disposal Act, 42 U.S.C. §6901 et seq.; National Environmental Policy Act, 42 U.S.C. §§4321 -4347. 39 The Federal Energy Regulatory Commission is an independent federal agency established under the Federal Power Act with, among other duties, responsibility for the regulation of transmission and wholesale sales of electricity in interstate commerce, insuring the reliability of high voltage interstate transmission systems, and oversight of certain environmental aspects of major electric generation projects. Official website, www.ferc.gov. 40 Homepage, Virginia Department of Environmental Quality, www.deg.state.va.us 41 National Environmental Policy Act, Title I, 42 U.S.C. § 4331.


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interstate transmission grid must be allowed; however, the conditions and special rates which can be charged should the proposed facility not meet requirements pertaining to generation, stability of operation, and potential risk factors to the grid must be considered and addressed as early as possible. This is an area which may develop as the project itself grows. Due to the specialized nature of any filings or submissions under FERC rules, and since it is likely that all power sales would be as a result of the intervention of a licensed electric power broker, implications of any FERC role should probably be left to the broker. In addition, many of the aspects of this connection to the interstate grid are in practice handled through the Virginia State Corporation Commission’s (SCC) oversight of state electric power generation and rates. The United States Department of Energy (DOE) mission is to advance and promote energy technology.42 DOE’s most likely involvement with the proposed bio-refinery would be as potential source of grant or other funds or in supporting research and development aspects of the project.43 A major funding role will likely require environmental findings and documentation under NEPA.

3.4 State Permits and Licenses

3.4.1 Energy Policy Virginia has enacted an Energy Policy that supports development of renewable energy, promotes generation of electricity through technologies that do not contribute to green house gases and global warming, and seeks to reduce demand for imported petroleum by developing alternative technologies including alternative fuels. State agencies and political subdivisions are directed to recognize and take discretionary actions which are consistent with the goals of the Commonwealth Energy Policy.44 The proposed integrated bio-refinery is entitled to recognition and due deference under that Policy.

3.4.2 Virginia Department of Environmental Quality Federal delegated environmental and public health programs are administered by various offices of the Virginia Department of Environmental Quality (DEQ).45 Any facility planned, constructed, and operated to implement the integrated bio-refinery proposal must comply with DEQ regulations and will be required to obtain permits before final construction and beginning operations.46

42 www.energy.gov. 43 www.energy.gov/r&dsupport.htm. Note: Idaho National Laboratories is participating in the preparation of this document and is assisting the Project in providing technical language for bidding processes necessary to implement subsequent stages of the project. 44 56 VAC §§ 67-101, 102. 45 See, www.deq.state.va.us, This homepage contains a complete reference of pertinent laws and regulations, permits, and a guide to permitting authorities which is comprehensive and most helpful. 46 State permitting conditions and emissions standards must reflect federal regulations and may be more strict in efforts to control and reduce pollution and protect public health but may not be less stringent that the federal rules. Virginia permitting processes provide for the concept of allowing simultaneous construction and operation of a facility thus somewhat streamlining the permit process for the applicant. Interview, Darton and Gossett, n. 5


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3.4.3 Waste Management and Compliance The State Waste Management Board of the DEQ is responsible for carrying out the purposes and provisions of the Virginia Waste Management Act and compatible federal act provisions and is authorized to exercise general supervision and control over waste management activities in the Commonwealth.47 The Board not only develops management plans and collects data, it has promulgated regulations necessary to carry out that responsibility and issues permits for operations. These regulations including application criteria and all procedures are published online.48 The Board has also articulated policy applicable statewide prioritizing methods for managing waste; and, as noted earlier, the least preferred method is by landfilling.49 Thus, to the degree that a proposal is submitted for Board approval that offers a methodology for managing and disposing of waste that provides for incineration, resource recovery, reclamation or reuse, as the proposed integrated bio-refinery does, that methodology will be viewed favorably by the Board.50 Waste management permits may also be granted pursuant to what is called the “Permit-By-Rule.”51 Virginia waste permit regulations include provisions for emergency and experimental permits which will provide additional flexibility to the permitting process which is innovative and for which specific terminology may not be clear or explicit standards may not yet have been published.52 When a proper and complete application is filed with the DEQ detailing the permit sought and complying with specific requirements, the Board representative must rule on the permit application within a prescribed time or the permit is deemed to have been granted. Once technology is selected for the proposed integrated bio-refinery project and a complete permit application is submitted for action, time delay may expected to be minimal due to the positive preliminary contacts made by the Green Initiative Committee with the Northern Virginia Regional Office Waste Program personnel.

3.4.4 Air Pollution Compliance The State Air Pollution Control Board of the DEQ is authorized to make regulations for the control and abatement of air pollution throughout the Commonwealth or in affected areas, to issue permits for construction, modification and operation of polluting facilities and collect fees for the administrative and enforcement costs of such permits for major facilities and to enforce its regulations.53 Those regulations are published on line and set forth the pertinent standards and application criteria for the permits which would be needed by any entity seeking to either contract with Fauquier County government or to build on its own a facility

supra.; Air quality permits are issued to industries and facilities that emit regulated pollutants to ensure that these emissions do not harm public health or cause significant deterioration in areas that presently have clean air. The permit also ensures that facilities make adequate provisions to control their emissions. Virginia regulations for the Control and Abatement of Air Pollution set out criteria for deciding if any new proposed facility or any change to an existing facility are contained in the for the Control and Abatement of Air Pollution The Northern Virginia Regional Office, one of the seven DEQ reviewing offices, will determine the criteria applicable and decide upon issuance of air permits based on the facility. www.deq.state.va.us/air/permitting/homepage. 47 9 VAC 20; Va. Code § 10.1 -1400 et seq. 48 See, www.deq.state.va.us/. 9VAC 20-80. 49 Ibid. Interview, Dorsey, n. 24 supra. 50 9 VAC 20-80-30; Va. Code 10.1 §§1400-1457. 51 Interview, Richard C. Doucette, Waste Program Manager, Northern Virginia Regional Office, DEQ, April 30, 2007. 9VAC 20-80-485. 52 9 VAC 20-80-485 B and C. 53 9 VAC 5.


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such as is proposed by the integrated bio-refinery project.54 It is not possible to determine precisely which permit application process should or would be selected, or to state the probable timeline for approval of a permit to construct and operate a facility designed both to produce electricity and a bio-fuel from municipal, construction and other waste until the precise technology is selected.55 Virginia’s Air Emissions Program differs from federal and other delegated programs in that Virginia may issue a permit which allows simultaneous construction and operation under appropriate conditions.56 Informal preliminary contacts made by citizens supporting the integrated bio-refinery proposal with the Northern Virginia Regional Office demonstrate that, while a proper and complete application for a permit will need to be submitted to allow construction and operation of any facility erected in Fauquier County utilizing waste from the County landfill or other biomass materials, the permitting process can proceed as expeditiously with the required public participation notices, hearings, comments and rulings likely being the primary time consumer. 57 One matter ancillary to the application for and receiving of an air emissions permit is that, depending upon the permit, there will be a fee associated with it, and this cost should be factored into the permitting process.58

3.4.5 Water Control Permits The Fauquier County Landfill site already has in place all required water monitoring devices, and no need for any additional monitoring is presently considered likely because of the purpose and probable design for the proposed facility. However, during the initial contacts with DEQ Waste Program officials, the Northern Regional Waste Program Manager stated that he had discussed the proposal with the person responsible for Water Permits and that they both concurred that the proposed integrated bio-refinery seemed unlikely to adversely impact water resources of the Commonwealth. Further, there was discussion of the fact that any facility which might reduce both methane pressures on underground waters from the existing site and offer potential reduction of runoff contamination by nitrogen and other

54 The federal Clean Air Act Amendments of 1990 requires the states to deal with air quality issues including health-based standards for six “criteria pollutants”—carbon monoxide (CO), lead (Pb), nitrogen oxides (NOx), ozone (O2), particulates, and sulfur oxides (SO2) as well as certain “hazardous” pollutants not within the sir quality standards criteria. Virginia regulations not only administer federal programs and regulatory provisions but include some issues not addressed under federal law such as controlling dust sources to prevent particulates from becoming airborne and prohibiting odors “objectional to individuals of ordinary sensibility.” www.deq.state.va.us/air/permitting/xcaa; . 55 Electronic communication, Terry H. Darton, Environmental Engineer Consultant, Northern Regional Office, DEQ, June 22, 2007 2:53:34 PM EDT. Permit types are categorized as to the potential of a facility to emit regulated pollutants. This potential is determined by the amount – and to some extent the type – of waste and other feedstock involved in the regulated facility process. Until a technology is selected and a capacity for that technology is selected with regard to the amount of material to be processed, the type of permit applicable to the facility and level of controls on potential emissions is conjectural. State Air Program personnel have offered assistance to aid the Green Initiative in determining which permit to seek when the time is appropriate. Interview, Terry H. Darton, Environmental Engineer Consultant, Air Program, Northern Regional Office, May 15, 2007; Interview, Darton and Gossett, n. 5 supra. 56 Interview, Darton and Gossett, June 20, 2007, n. 5 supra. The Virginia Air Operating Permit System is a new, streamlined system which seeks to place all air permitting requirements for a facility into one single permit. This permit is then subject to renewal every five-years to allow changes reflecting both facility needs and changing regulations. www.deq.state.va.us/air/permitting/xcaa. 57 Interview, Darton and Gossett, Ibid. No precise time table can be stated until an application is submitted, but, if the permit process determined to be applicable is the most onerous, it could take as much as a year to complete. 58 Ibid.


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pollutants produced by biomasses which could act as additional feedstock for the facility would likely be environmentally beneficial.59

3.4.6 Virginia State Corporation Commission The Constitution of Virginia vests in the State Corporation Commission (SCC) the duty of regulating the rates, charges, and services of electric companies and, except as otherwise authorized, their facilities.60 The Division of Energy Regulation implements these SCC duties as well as issuing certificates of convenience and necessity requisite for construction and operation of certain facilities by electric and other utility companies and performing other regulatory, licensing and enforcement functions.61 Specifically, by statute, the SCC “may license natural gas and electric suppliers and govern the marketing practice of natural gas and electric suppliers.”62 Regulations pertinent to SCC operations are published online.63 The SCC has set filing requirements for entities applying to construct and operate electric generating facilities, divided as to whether the expected capacity of the facility is greater than 50 Megawatts or is 50 MW or less, as well as discussing the applicability of the requirements.64 Preliminary contacts initiated with the office of General Counsel with regard to the applicability of SCC requirements to the proposed integrated bio-refinery project have resulted in a statement that “the [Virginia] Code is not a [sic] clear as it might be in this regard. It is the position of the Commission’s Office of General Counsel and Division of Energy Regulation that the project’s developer, owner or operator should file a petition with the Commission pursuant to the provisions of Code Section 56-580 D to secure a construction permit for the facility. The Commission will not regulate rates from the facility, but must permit its construction under the criteria set forth in that provision.”65 A further communication from the Office of General Counsel indicated that, while time constraints for the petition and permit approval process are not totally predictable, “generally speaking the smaller and less controversial a filing is, the quicker it can be handled….I would hope we could get through a filing in about 4 months or so.”66 While the listed requirements do not include a mandatory public participation element, it is possible that since a public notice and participation component is part of the permitting process for both DEQ Waste and Air Emission Programs, and there is a required comprehensive environmental review process for any proposed generation facilities, it is both desirable and wise to coordinate any SCC application procedures with those for the DEQ.67 Conclusions Based on the information for the regulatory agency processes concerned with approval of an integrated bio-refinery designed to produce both electricity and bio-fuel, it would appear that a reasonable time frame between selection of the technology to be used and its facility design completion and ground breaking should be between fifteen and twenty-four months, contingent on the availability of appropriate machinery.

59 Interview, Doucette, n. 48 supra. 60 Article IX, Section 2 of the Constitution of Virginia. 61 Va. Code, Title 56, Chapters 1, 9.1, 10, 10.1 and 10.2:1; Title 15.2, Ch. 43. 62 Va. Code Title 56, Chapter 10; 9VAC 5. 63 www.state.va.us/scc/division/pue/ 64 20 VAC 5-302, 5-302-20, 5-302-25, and 5-302-10. 65 Electronic communication, [email protected], June 25, 2007 9:41:54 AM EDT. 66 Electronic communication, [email protected], June 25, 2007 11:58:30 AM EDT. 67 Ibid. Va. Code 56-580D, Va. Code 10.1-1186-2:1.


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4 Technology Assessment There have been some interesting recent developments in the field of plasma gasification that ANTARES believes are of importance. An article in the October issue of Biomass magazine describes how several plants are using plasma to process municipal solid waste (MSW) into electricity. Plasma technology has been around for decades but only recently has it started to be used commercially for the production of energy from MSW. The article focuses on a plasma gasification plant in Ottawa Canada that can processes 85 tons per day of MSW. The city of Ottawa has teamed up with Plasco Energy Group Inc. to deliver the plasma technology. The Plasco system uses a variation of traditional plasma technologies. Their system uses a separate gasification chamber to gasify the MSW. The plasma is then used to refine the gas, as opposed to refining the shredded up MSW. The refined syngas is then used to produce 5 MW of electricity for every 100 tons of MSW. 4 MW are sold to the grid and 1 MW is used to power the plant. All that is landfill is 1 kg of ash. Construction on the plant finished in June and it started processing MSW in late September. Plasco is planning to build another plant in Spain and two more in Canada in the near future. The largest plant to date is planned to start up in 2010 in St. Lucie County, Florida. The energy developer is Geoplasma LLC and the technology provider is Westinghouse Plasma Corp. The plant will start by processing 1,000 tons per day and eventually reach 3,000 tons. St. Lucie county expects to completely consume their landfill within 20 years. Another story of interest is the recent news that Volkswagen and Daimler have acquired a minority shareholding in CHOREN Industries, a gasification vendor. CHOREN’s plants use a Shell technology that converts synthetic gas into liquid fuels. This technology is based on the Fischer-Tropsch process. CHOREN is currently building the world’s first commercial biomass to liquid plant in Freiberg, Germany. The facility will produce 4.6 million gallons of fuel per year, and be the test model for future plants capable of producing 61 million gallons per year. Their technology uses a three-stage gasification process that occurs in low temperature, high temperature, and endothermic conditions. Through their investment, Volkswagen and Daimler are trying to promote the use of biomass derived liquid fuel. This commitment is part of Volkswagen’s “Driving ideas” campaign to support sustainable mobility. The Pacific Northwest National Laboratory conducted a review of gasification technologies that could be employed to convert MSW to ethanol. That report was conveyed to the Mayor of Warrenton as a separate document. That report is in draft form and therefore is used only as an advisory input to the findings of this report. Technologies reviewed in the PNNL report include: Company Technology Ebara Fluid bed gasification, secondary combustion, melting Nippon Steel Gasification & secondary combustion & melting Mitsui Pyrolysis secondary combustion & melting Technip Thermal Gasification Thermoselect Pyrolysis gasification and melting Von Roll Pyrolysis secondary combustion & smelting Brightstar Environmental 2 stage gasification Compact power Pyrolysis, gasification, combustion PKA Pyrolysis, gasification, & melting


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At this stage all of the technologies proposed to be used to gasify MSW and then convert the syngas to ethanol are in a developmental stage. Any project developed on this basis would therefore be experimental and would entail significant risk. The benefits of converting biomass in the MSW stream to power or liquid fuels are well recognized: • Biomass makes up typically 60 -70% of MSW • Diversion of the biomass portion of MSW to fuels extends landfill capacity • Diversion to fuels reduces greenhouse gas emissions attributed to decomposition of the

biomass in landfills and displacement of fossil fuels used in energy production A pilot plant built on technologies to convert MSW to liquid fuels is clearly in the national interests and a major portion of the risks associated with the first time use of these technologies could be offset by Federal and State funding to demonstrate the application of the technology. Under those circumstances an investment in a pilot plant could be made by a municipal utility or public works department. In the following section we describe conceptually how that plant would be configured and what the range of product throughput and cost is likely to be.

4.1 Prototype Conversion Plant Configuration, Cost and Performance

4.1.1 Feedstock Processing The trend in MSW handling is toward increased waste reduction and separation of components for recycling. This has been extended to separation of biomass components of the waste stream by Taylor Recycling and others68. Transfer stations and recycling centers are a necessary ingredient in a project that demands a consistent feedstock with as few non-productive contaminants as possible. Removing metals, glass and treated biomass from the feedstock stream significantly reduces the capital and operating cost of a gasification facility and helps to assure good environmental performance. The feedstock for a municipal Biorefinery project should be biomass with very little contamination. This will of course add to the cost of managing wastes and would be reflected in the price of the feedstock provide by municipal waste authorities to the conversion facility.

4.1.2 Plant Feedstock Receiving and Storage The goal of the project is to manage deliveries of feedstock in a manner that minimizes onsite storage and management. In the best of all worlds just in time deliveries to the facility with daybin storage of 18 to 24 hours of feedstock materials would meet that goal. Being able to minimize onsite storage of biomass has significant implications for project siting. Meeting this goal is essential to minimizing plant siting and permitting risks

4.1.3 Feedstock Processing With one notable exception (hydrothermal gasification) gasifiers require low moisture feedstocks – generally less then 15%MCW and manageable particle size and density. Generally gasifiers will accommodate material screened to 2” minus. For this type of project

68 http://www.taylorbiomassenergy.com/company/?id=2


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a pelletized fuel like that produced on a pilot scale for Wisconsin Electric by Americology would be ideal in terms of moisture content, density and uniform size.69

4.1.4 Gasification Of the experimental technologies reviewed several could be considered for a pilot scale facility: Alico Inc, Range Fuels and Pearson Technologies Inc for Ethanol production, Carbona Energy and Taylor Biomass for Power production. For this technology review two technologies will be used as prototypes for a pilot facility in Warrenton: • Range Fuels gasification and mixed alcohols process was selected by DOE for a cost

shared grant to build a pilot plant in Georgia that will produce 10MGY of alcohols by 2011. At commercial scale the plant will be design to product 40MGY EtOH and 10MGy MeOH.

• Carbona is currently building a pilot facility in Skive Denmark and Taylor Biomass is advancing a gasification system that is based on knowledge gained at a pilot scale system built by FERCO at the McNeil Plant in Burlington VT.

These technologies are all proprietary and our estimates of performance and cost are based on studies of the processes that are used in these technologies. Actual performance will vary from these estimates.

4.2 Lignocellulosic Biomass to Mixed Alcohols: Thermochemical Conversion

Technology Description Range Fuels uses a proprietary process that is similar to the process described here. The conversion of Lignocellulosic Biomass to Mixed Alcohols via Thermochemical synthesis is related to Fischer Tropsch (FT) synthesis which had been used commercially for coal to liquids production most notably in South Africa. However the end products are alcohols not distillates. Figure 25 shows a block diagram for the process. Higher Alcohol Synthesis (HAS) is done in reactors similar to those used for FT and methanol synthesis. The most effective types of catalysts include modified methanol synthesis catalysts, modified FT catalysts, and alkali-doped molybdenum catalysts (Nexant Inc. 2006). The modified methanol synthesis and Mo catalysts show higher alcohol yields than modified FT catalysts. The Mo catalysts also have the best selectivity for higher alcohols, and a high tolerance for CO2 and sulfur in the syngas (Nexant Inc. 2006). However, although this higher sulfur tolerance requires less clean-up of the syngas before conversion, it may require sulfur removal downstream in the mixed alcohol fuel.

69 EPA 600 S2-85 116


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Figure 25 Schematic diagram of thermochemical ethanol production process

Biomass

Pre-treatmentSizingDryer

Conversion / Alcohol Synthesis

Alcohol Separation

Ethanol

Gas Clean-up&

Conditioning

Heat / Power Production

Ash

GasifierSyngas

Other Alcohols

Biomass





Alcohol Separation

Alcohol Separation

Ethanol

Gas Clean-up&

Conditioning

Gas Clean-up&

Conditioning



Ash

GasifierGasifierSyngas

Other Alcohols

Diagram based on Figure in Phillips et al. (2007) The process involves complex set of reactions that produce a variety of products, depending on catalyst used and process conditions. The major reactions include methanol synthesis, FT reactions, higher alcohol synthesis, and water-gas shift. The process is optimized at syngas compositions with ratios of H2/CO ~ 1 (Spath and Dayton 2003). Regardless of the type of catalyst used, typically 40 to 90% of product stream needs to be recycled to maximize mixed alcohol production (Nexant Inc. 2006). The main by-products of the process are CO2 and water, and large quantities of methane are also often produced. Technology Status Although the process to generate higher alcohols from syngas has been known since the early 1900’s, the technology has not yet reached commercialization (Spath and Dayton 2003). As of April 2005, there were no commercial plants that solely produce mixed alcohols in the C2 to C6 range (Nexant Inc. 2006). However, Range Fuels, Inc. is planning a demonstration facility to generate ethanol and other alcohols via thermochemical conversion (see details below). The main technical hurdles for higher alcohol synthesis include poor selectivity to higher alcohols and low yields. Typical conversion rate for single pass processes is about 10% production of alcohols, which is mostly methanol (Spath and Dayton 2003). The methanol can be recycled back through process to generate higher alcohols. Research and development efforts for HAS have been performed by several companies since the early 1980’s. Some of the most advanced processes were developed by DOW, IFP and Snamprogetti (Spath and Dayton 2003). However, none of these companies are currently active in this area of research (Nexant Inc. 2006). Recent efforts for commercialization of the process have been spurred by new catalyst developments, new project developers, and the interest in alternative fuels (Nexant Inc. 2006). Some of the current commercialization efforts are described below based on information from Nexant Inc. (2006): • Pearson Technologies has a 30 ton/day biomass gasification with syngas conversion to

alcohols in Aberdeen, Mississippi. Pearson is also trying to develop a demonstration plant in Hawaii.

• As mentioned above, Range Fuels Inc. is developing a 1,200 ton/day (wood chip input) demonstration facility to generate ethanol and methanol. This project is supported by DOE and is scheduled for completion in 2011 (see U.S. DOE 2007).

• Power Energy Fuels is continuing to work on their proprietary EcaleneTM process. Although this process is currently only developed at the bench-scale, there are 2 or 3 pilot plants under consideration which would produce mixed alcohols from biomass sources (wood chips, RDF, and tires). One of these pilot facilities is a 2,000 gallon per


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day plant that would be located at Wabash River Coal Gasification facility (with ConocoPhillips).

• Standard Alcohol Company of America is continuing to work on their EnviroleneTM process. This is only a bench scale process currently, but the company is interested in developing a pilot.

Despite this recent surge of development, there are still a number of technical and economic hurdles that must be overcome for the commercialization of the conversin process. According to Nexant Inc. (2006, p. 3-2), the primary technical barriers include: “the overall process feasibility to produce the desired product slate, the ability to scale-up the process to a commercial level, the appropriate process conditions both in the reactor and upstream units, performance of various catalysts at commercial conditions, catalyst sensitivities, and appropriate syngas compositions.” Additionally, large-scale mixed alcohol synthesis will require detailed consideration of the market interest and production costs relative to other fuels. Performance and cost analysis Antares developed a performance and cost model for thermochemical ethanol production via mixed alcohol synthesis based on recent work by NREL (Phillips et al. 2007). NREL developed a detail process model and economic analysis for a projected thermochemical ethanol facility. The analysis is based on the DOE targets for synthesis yields and selectivity for a 2,205 dry ton/day facility (equivalent to 772,000 ton/yr for a plant with 96% availability). The NREL model configuration uses an indirect steam gasifier and a conventional steam power cycle. The syngas clean-up and conditioning step includes tar reforming, water scrubbing (for cooling and quench), and acid gas removal. Clean syngas is converted to alcohols in a fixed bed reactor, using a MoS2 catalyst with a very high ethanol selectivity. 70 The alcohol separation section includes dehydration and separation of alcohols. Methanol is recovered and recycled through the alcohol synthesis section to increase yield of ethanol and higher alcohols. A portion of the unconditioned syngas is diverted from to generate electricity and heat. Although this model produces exactly the amount of energy required to sustain the process (consuming 28% of the syngas), an actual plant could vary the energy production depending on favorable market conditions to buy or sell electricity from the grid. If all the syngas was converted to alcohols, the ethanol yield would be 110.9 gallons per dry ton of biomass, and the total alcohol production would be 130.0 gal/ton (Phillips et al. 2007). With 28% of the syngas used for energy production, the ethanol yield is 80.1 gal/ton. Antares has scaled down the capital cost and throughput for a Biorefinery at the 200 dry ton per day capacity. Our preliminary estimate of output is 6 MGY Ethanol. Because of many uncertainties in the process design at this stage the capital cost can only be very roughly

70 This is a modified Fischer Tropsch catalyst based on the former Dow/UCC catalyst, with conversion performance modeled based on target results. In addition to higher total CO conversion and higher alcohol selectivity, the projected distribution of ethanol and methanol used in the NREL model differ from current results. The Phillips et al. (2007) model assumes that 71% of the alcohol production is ethanol, and 5% is methanol. In contrast, the Dow distribution was 30-70% methanol and 34.5% ethanol.


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estimated for a pilot plant - $72 Million. If the process was commercialized and performance targets met the capital cost could be potentially cut in half. References

1. Nexant Inc. Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment. Task 9: Mixed Alcohols from Syngas - State of Technology. NREL subcontractor report no. NREL/SR-510-39947. 2006.

2. Phillips, S., et al. Thermochemical Ethanol Via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass. NREL technical report no. NREL/TP-510-41168. 2007.

3. Spath, Pamela L., and David C. Dayton. Syngas Analysis - Preliminary Screening, Technical Briefs, and Technical Barrier Assessment for Syngas to Fuels and Chemicals. National Renewable Energy Laboratory. June 30 2003.

4. U.S. DOE. DOE Selects Six Cellulosic Ethanol Plants for Up to $385 Million in Federal Funding. February 28 2007 <http://www.energy.gov/news/4827.htm>.

4.3 Power Generation There are a number of technology choices for gasification based power generation. These include mature, close coupled gasification (multi-staged combustion) and more advanced cycles that rely on prime movers such as reciprocating engines or gas turbines. The latter are the focus of intense research, development and demonstration.

4.3.1 Close Coupled Gasification (Multi-staged Combustion) Several technology vendors now offer a technology aimed at gaining improved performance over traditional wood fired boiler systems. These technologies are referred to as hybrid biomass gasifiers/combustors, close coupled gasifiers or staged combustion units. These systems are often contained within a single vessel (may use more than one) where a gasification zone is established to vaporize the volatile gases from the solid fuel. The heat for this reaction is driven by carbon remaining on the reciprocating grate. The combustion chamber above the gasification zone will mix the volatile gasses with combustion air and transfer the heat from the gas to generate steam from the feedwater. This technology has several advantages over the other technologies considered. These are primarily derived from the maturity of the technology. There are a few key disadvantages as well, marked primarily by technical limitations of the technology. In context of overall fuel and capital efficiency, these systems can be very competitive. System like this are offered by a variety of vendors at a variety of scales. Manufacturers at smaller scales include Hurst Boilers, Chiptec, and NEXTERRA. At larger scales, Energy Products of Idaho and Foster Wheeler have experience in this area. Historically the smaller systems have found a niche in heating applications, but under the right economic circumstances, cogeneration and power generation only applications are possible. Larger systems are more applicable to cogeneration and industrial/utility scale power. Several schematics for potential systems are shown in figures Figure 26 and Figure 27 below.


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Figure 26 Schematic for Close Couple Gasification System at University South Carolina

Source: JCI/Nexterra Press Release: www.nexterra.ca/industry/johnson.cfm Figure 27 Diagram of Steps in Gasification Process

Source: Chiptec website, www.chiptec.com


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4.3.2 Advanced Gasification Power Cycles Reciprocating IC engines are commonly used for standby power generation in commercial, industrial and institutional buildings or by facilities requiring continuous power that are not connected to the electric grid. Most of the reciprocating IC engine plants are under 5 MW in capacity. The predominate sources of fuel for reciprocating IC engine generator sets in the biomass industry have been landfill and digester gases. The use of wood gas in engines has not been demonstrated or commercially performed in the United States, although this technology has been demonstrated by GE Jenbacher in Europe at several locations. Other engine manufacturers such as Caterpillar and Waukesha have used landfill gases, but no other engine manufacturer has been as willing as GE Jenbacher to use wood gas due to its low energy content and gas clean-up issues. The primary piston engine design relevant to this power generation application is the spark-ignition (SI), 4-stroke Otto-cycle engine. The essential mechanical components of the Otto-cycle are a cylindrical combustion chamber in which a close-fitting piston travels. Spark-ignition engines (Otto-cycle) use a spark plug to ignite a pre-mixed air-fuel mixture introduced into the cylinder. The piston is connected to a crankshaft that transforms the piston’s linear motion into rotary motion. Most engines have multiple cylinders that power a single crankshaft. For power generation applications, the crankshaft drives an AC generator. Reciprocating engines are categorized by their original design purpose – automotive, truck, industrial, locomotive and marine. The engines intended for industrial use are designed for durability and for a wide range of mechanical drive and electric power applications. They range from 20 kWe up to 11 MWe output and include industrialized truck engines in the 200 to 600 kWe range and industrially applied marine and locomotive engines above 1 MWe. Although there is extensive information available on costs, performance and operating history of gas engines, there is far less commercial experience in using low Btu gases for fuel. This is especially true for gases derived from biomass gasifiers. Beyond the low energy density of biomass gas, cleaning the producer gas of particulates, heavy hydrocarbons and other compounds potentially damaging to the engine remains a significant technical and economic challenge. At this point in the technology development cycle there are numerous vendors competing to offer commercially viable power generation technologies. Any detailed discussion is further complicated by the fact that most are focusing on cogeneration (or combined heat and power) because of the overall high thermal efficiency of such projects. Although this aspect of the cycle configuration is not entirely applicable, these projects do provide a basis for understanding the technical issues surrounding power only projects. Note that additional data on several power only projects is also provided below. By way of example, the Finnish company Carbona Oy (Carbona Corporation is an affiliate), incorporated in 1996 and spun off from Tampella Power’s interest in biomass gasification and the 20 MWth biomass gasification pilot plant constructed in Tampere, Finland. Carbona also has gained the licensing rights to the Gas Technology Institute’s developed pressurized fluidized bed gasification process and is the licensed vendor of Condens Oy’s Novel CHP plant previously discussed. Carbona states their atmospheric fluidized bed gasifiers are available between 5 MWth and 100 MWth for generating product gas to be used in boilers, lime / cement kilns, and engines. Carbona has gasification experience with woody biomass, agricultural residues, paper mill sludge, and plastics.


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The project in Skive is a cogeneration project. Development terms are reported to be commercial but subsidies are being provided by the US Department of Energy, the European Union and the Danish Energy Agency. The owner of the project is Skive Fjernvarme and is acting the main contractor with the responsibility of integrating the various parts of the CHP plant. The new plant will replace an existing district heating plant at the same site. The plant is designed to use 110 tons per day of wood pellets with a moisture content of 9.5%, the gasification CHP plant in Skive will produce 5.5 MWe from three Jenbacher gas engines and 11.5 MWth of district heat. The process will produce a low Btu gas with a lower heating value (LHV) of 5.5 MJ/Nm3 from the fluidized bed gasifier and after the gas clean up. A schematic of the process at Skive is shown in Figure 28 below. Ground breaking for the plan was initiated in April 2005 (Babu 2006), and hot commissioning was scheduled to start in 2007 (Patel 2006). Figure 28 Skive CHP Gasification Plant

GASIFIER

GAS FILTERGAS COOLER

GAS ENGINES

TAR REFORMER

BIOMASS

AIR & STEAM

ASH

FLY ASH

BOILER

TO STACK

WATER

GAS SCRUBBING

GAS BUFFER TANK

DISTRICT HEATING11.5 MWth

POWER5.5 MWe

GASIFIER

GAS FILTERGAS COOLER

GAS ENGINES

TAR REFORMER

BIOMASS

AIR & STEAM

ASH

FLY ASH

BOILER

TO STACK

WATER

GAS SCRUBBING

GAS BUFFER TANK

DISTRICT HEATING11.5 MWth

POWER5.5 MWe

Carbona is also reportedly developing a gasification project in Andhra Pradesh, India. Less information is available regarding this project, but the design concept is an integrated Gasificatoin Combined Cycle (IGCC), power only project with a nominal net plant output of 12.5MWe. The project will consume approximately 210 tons per day of woodchips with a design moisture content of 20 percent. The project configuration employs two 4.7MWe gas turbines and a 4 MWe bottoming cycle. The status of this project is unclear, but the scale is consistent with the expectation that a biomass IGCC project must be at least 10MWe to be technically practical.


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Taylor Biomass LLC is currently developing a technology that combines an MSW separation and recycling plant with a biomass gasification process. The targeted end products for the system include power, heat, liquid fuels, and hydrogen. A representative block flow diagram of a Taylor Biomass Energy Facility Process (www.taylorbiomassenergy.com) is shown in Figure 29 below. Figure 29 Block Flow Diagram of Taylor Biomass Energy Process

Specific flow diagrams for the plant are proprietary, but the a similar technology was planned for a biomass generation project that was under development by Peninsula Power. That project was designed to produce heat and power from locally sourced energy crops (short rotation willow coppice and miscanthus) other forestry products, clean waste wood and cellulose fiber. The project was expected to produce about 23 MWe (gross) of electricity. The site for the project is a 10 acre plot located on the former Winkleigh Airfield approximately 1.2 miles from the town center. The project is designed to supply fuel to a 12.9 MWe SGT-400 gas turbine supplied by Siemens (formerly the Alstom Cyclone). The exhaust gas from the turbine will be used to fire the heat recovery steam generator (HRSG), which will drive the Siemens SST-100 steam turbine. A diagram of the Winkleigh process is shown in Figure 30 below. The gasifier selected for the project was FERCO’s Sylva Gas process. This process was demonstrated in a cofiring application sponsored by the U.S. Department of Energy at McNeil Generating Station in Burlington, Vt. This indirect gasification process produces a medium Btu gas. Unfortunately, the future of this project is unknown as it appears to have gotten mired in a permitting issue late in 2006.


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Figure 30 Winkleigh IGCC Project

4.3.3 System Performance and Costs The following system and performance data (Figure 31, Figure 32, Figure 33) is representative of information collected across a variety of technologies, vendors and scales. They are representative of the information that ANTARES used in its economic analysis for the power options performed in this study. However, as necessary, modifications to these data were made to account for the specific configuration and applications considered. Figure 31 Boiler w/Steam Turbine System Performance Projections Plant Size MW 3.4 10 10 15 15 25Capacity factor Percent 90 90 90 90 90 90Net heat rate Btu/kWh 20,400 26,686 26,686 26,508 26,508 11,373Total Capital 2004$/kW 3,735 2,875 3,570 2,476 3,116 2,540Fixed Operating 2004$/kW-yr 262 270 300 219 254 89Variable operating 2004 C/kW-hr 0.00 0.00 0.00 0.00 0.00 0.58


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Figure 32 Gasifier w/ Steam Turbine Plant Size MW 50 50 60 75 100 100 Capacity factor Percent 80 90 80 90 80 90 Net heat rate Btu/kWh 14,486 11,373 12,325 11,373 12,325 11,373 Total Capital 2004$/kW 2,191 2,062 1,946 1,829 1,684 1,681 Fixed Operating 2004$/kW-yr 81 80 67 77 67 75 Variable operating 2004 C/kW-hr 0.95 0.58 0.78 0.58 0.78 0.58 Figure 33 Gasifier w/Reciprocating Engines Plant Size MW 2.16 2.16 8.88 8.88 14.8 14.8 Capacity factor percent 90 90 90 90 90 90 Net heat rate Btu/kWh 10,520 10,520 9,175 9,175 9,175 9,175 Total Capital 2004$/kW 5,263 8,020 3,631 5,204 3,197 4,770 Fixed Operating 2004$/kW-yr 410 507 144 171 93 111 Variable operating 2004 C/kW-hr 1.07 1.07 1.07 1.07 1.07 1.07

5 Economic Analysis The feedstock supply study gave the project team a good idea of how much biomass fuel is available for the proposed project and what feedstock costs to expect. Next, efforts were focused on evaluating different types of energy plants that can produce either liquid fuels or electricity. It was assumed that the available feedstocks can be used for the production of either end product. The feedstock costs associated with each are the same and are based upon best estimates from the feedstock supply study. Analyses were performed utilizing both MSW and wood residues as feedstocks. In each scenario, MSW was assumed to cost -$13/ton. This is the avoided cost of paying the landfill operator who would otherwise bury the MSW. For the wood residues, it was assumed that the non-recyclable portion of C&D brought to the landfill would be used a fuel source. The Fauquier county landfill brings in about 40,000 tons/year of C&D. This translates into roughly 130 tons/day. It was assumed that the current $46/ton tipping fee could be reduced to $20/ton for the energy facility. For the remaining 120 tons/day (to equal the base case 250 ton/day plant) it was assumed that wood chips would be used. This resource is prevalent in the area, and it’s its consistent nature makes it a desirable for energy projects. Assuming wood chips cost $35/ton, the project team arrived at a weighted average price for wood resides of $6.40/ton.

5.1 Ethanol The first scenario considered was a biomass-to-liquid fuel plant that would mainly produce ethanol, along with some other mixed alcohol byproducts. Figure 34 and Figure 35 below show the plant gate prices of ethanol given internal rates of return and feedstock costs. The feedstock costs represent MSW (-$13/ton), a combination of C&D and wood chips ($6.40/ton), and strictly wood chips ($35/ton). The summary tables show the effect of federal tax credits on the plant gate price. Please note that the discount rate used in these


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examples is 13.9%. This means that only the IRR’s above 13.9% will yield a positive Net Present Value (NPV). That is, only the IRR’s that are set at 15%.

Total Capital Costs: $71, 528, 15

Figure 34. Plant gate prices of ethanol with tax credits

Figure 35. Plant gate prices of ethanol w/o tax credits

Next, the same tables were created assuming that the project is awarded federal grant. In May 2007 The Department of Energy released a funding opportunity announcement supporting Section 932 of the Energy Policy Act of 2005. The FOA is for the demonstration of integrated biorefinery operations for producing biofuels. The award has a ceiling of $30,000,000 and a floor of $10,000,000. In addition, the cost share must be at least 50% of the total allowable project costs. Figure 36 and Figure 37 were generated under the assumption that the project receives a $30,000,000 DOE grant. The capital costs are then reduced to $38,750,930. As seen in tables, this drives down the plant gate prices of ethanol significantly.


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With DOE 30MD Grant

Figure 36. Plant gate prices of ethanol with tax credits Biomass Cost ($/ton)

IRR %1 -132 6.403 355 0.69 1.10 1.7010 1.07 1.47 2.0715 1.48 1.87 2.46

Figure 37. Plant gate prices of ethanol without tax credits

Biomass Cost ($/ton)IRR %1 -132 6.403 355 1.46 1.87 2.4710 1.84 2.24 2.8315 2.28 2.67 3.26


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5.2 Power The second scenario considered was using the biomass as fuel to produce electricity. There are numerous technologies available for producing electricity. Three were considered for this project, but the technology chosen for the base case analysis was gasification to Rankine Cycle steam. The product steam is then used to operate a turbine that produces electricity. The advanced nature of this technology requires that a 10% premium be put on the capital costs. There is currently much testing being performed on gasification technologies which should bring future costs. More traditional technologies are stoker plants which simply combust the feedstock to produce seam. More advanced technologies use a gas engine to operate the turbine instead of producing steam. The chosen scenario is a middle of the road case on the power production spectrum. As stated previously, the same feedstock prices were used for the power production scenarios that were used for liquid fuel production. To recap, -$13/ton was used for MSW and $6.40/ton was used for wood residues. Feedstock rates were assumed to be 250 tons/day in both cases. Other parameters are stated below. Wood/MSW Net Capacity (MW): 10/10 Annual Average Capacity Factor (%): 89/76 Full Capacity Generation (MW): 8.85/7.59 Annual Generation (MWh/year): 77,563/66,482 Total Investment Cost ($): 40,627,766/40,627/766 Total Fixed O&M ($/year): 1,684,483/1,684,483 Total Variable O&M ($/year): 553,090/474,077 Total Biomass Cost ($/year): 571,083/ (900,279) Figure 38 shows the Net Present Value (NPV) for the three different technologies considered at various electricity prices. The feedstocks rates were set at 250 and 400 tons/day for both MSW and wood residues. Cases 5 & 6 were the base cases considered in the analysis. The table shows that only at prohibitively high electricity prices will the project yield a positive NPV. Figure 38. NPV for Cases at Different Electricity Prices (13.90% Discount Rate, 20-yr Life)


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6 Rural Economic Impacts of a Small-Scale Biorefinery The ethanol industry in the U.S. has grown from a production level of just 175 million gallons per year in 1980 to an estimated 5.6 billion gallons of production at the end of 2006. The Energy Policy Act of 2005 (EPACT05) requires a minimum of 7.5 billion gallons per year of renewable fuels to be used in the nation’s highway fuel supply by 2012. Due to the requirements of EPACT05, rising oil prices that are expected to remain at high levels due to increased world-wide demand and supply constraints, growing concerns about global climate change, and national security concerns associated with maintaining a high dependency on foreign oil, the recent surge in investment and construction in ethanol production capability in the U.S. is expected to continue. As of October 2007, the Renewable Fuels Association estimates the total installed ethanol production capacity to be about 6.9 billion gallons per year at 131 Biorefineries in the U.S., with an additional 83 plants totaling about 6.5 billion gallons per year of production capacity under construction or expansion. At the end of 2006, 46 of the existing 110 ethanol Biorefineries were farmer-owned.71 Whether through ownership in the Biorefineries, or through providing raw materials, goods, and services to the growing number of ethanol Biorefineries, the growth of this industry has generated a significant new source of revenue and economic activity in rural communities in the U.S. While corn dominates as the raw material for today’s ethanol production, representing well over 90% of the grain input for current and near-term planned ethanol production, new feedstocks are expected to be required to sustain industry growth and approach government-announced targets for ethanol production of 35 billion gallons per year by 2017 with further increases thereafter to accomplish the displacement of 30 percent of 2004 gasoline use by 2030.72 Continued industry reliance on corn as the raw material for nearly all ethanol production is projected to create supply constraints and severe price inflation for food-based markets for corn, especially if the industry continues to grow at projected rates. As a result, the U.S. government is partnering with industry to develop and demonstrate the capability to produce ethanol economically and reliably using new feedstocks, such as the non-food portions of plants (including cellulose, primary structural components of plants) and non-food feedstocks including energy crops. Examples of such feedstocks include corn stover, wheat straw, wood, and a variety of grass species. The U.S. government is partnering with industry to build the first examples of commercial-scale cellulosic ethanol Biorefineries, and is also co-sponsoring research and development on new methods and technologies for producing ethanol from non-food feedstocks.

71 Ethanol production and industry statistics obtained from the Renewable Fuels Association, October 2007, http://www.ethanolrfa.org/industry/statistics/#EIO. 72 Biomass Multi-Year Program Plan, October 2007, Office of the Biomass Program, Energy Efficiency and Renewable Energy, U.S. Department of Energy, p. ii.


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In 2005, President Bush laid out aggressive goals for moving Biofuels into the marketplace to reduce the nation’s dependence on foreign sources of energy and reduce greenhouse gas emissions from the transportation sector. Specifically, the President’s stated goals are to achieve the following73: • Foster breakthrough technologies needed to make cellulosic ethanol cost competitive

with corn-based ethanol by 201274 • Increase the supply of renewable and alternative fuels to 35 billion gallons by 201775 Each year, the Renewable Fuels Association releases a report detailing the annual contributions of the ethanol industry to the economy of the United States.76 In the year 2006, their report states that the industry spent $6.7 billion on raw materials, other inputs, goods, and services to produce an estimated 4.9 billion gallons of ethanol with an additional $410 million spent transporting ethanol to blending terminals. The largest share of raw material expenses was for corn, totaling $4.1 billion. New capacity brought on-line in 2006 represented an additional expenditure by the ethanol industry of about $2.1 billion. The spending for goods and services represents the purchase of outputs from other industries. This spending circulates through the economy several fold, supporting the creation of new jobs, generating additional household income, and increasing tax revenues for all levels of government. Considering this multiplying effect throughout the economy, the report estimates that the ethanol industry added $23.1 billion to the nation’s Gross Domestic Product in 2006, resulting in the creation of 163,034 jobs in all sectors of the economy. Finally, the report estimates that the increased economic activity and new higher income level jobs resulted in putting an additional 6.7 billion into the pockets of American consumers in 2006. Based on a feedstock input of 400 tons per day, and a mixed alcohol production of about 9.6 million gallons per year, Figure 39 below lists the potential economic and environmental impacts of such a facility. Figure 39. Economic & Environmental Impacts of Alcohol Facility Warrenton Biorefinery ProjectEconomic and Environmental Impacts

Plant Profile Tax Revenues GHG Reductions Income$/yr Tons CO2eq/yr $/yr

Capital Cost $M 69$ 683,100$ -$ Feedstock Demand TPD 400 21,024$ 449 3,504,000$ Staffing FTE 20 57,500$ 1,000,000$ Output MGY 9.6 172,800$ 19,200,000$

Totals 934,424$ 449 23,704,000$ 73 Ibid, p. 1-1. 74 Advanced Energy Initiative. February 2006, The White House National Economic Council http://www.whitehouse.gov/stateoftheunion/2006/energy/energy_booklet.pdf. 75 2007 State of the Union Address, 20 in 10: Strengthening America’s Energy Security, http://www.whitehouse.gov/stateoftheunion/2007/initiatives/energy.html. 76 Contributions of the Ethanol Industry to the Economy of the United States, February 2007, prepared by LECG LLC (John M. Urbanchuk) for the Renewable Fuels Association. (http://www.ethanolrfa.org/objects/documents/2006_ethanol_economic_contribution.pdf)


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The project generates almost a million dollars in state and local tax revenues while creating approximately 20 direct jobs. Equally important the project diverts biomass from landfilling and offsets nearly 450 tons of carbon dioxide equivalents greenhouse gas potential.


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Appendix A

Fuel Characteristics for Various Biomass Fuels


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Wood Fuel Composition Data

As Received BasisSample Type Btu/lb* MCW^ Carbon Hydrogen Nitrogen Sulfur Ash OxygenSawdust (Green) 4,150 52.63 24.17 2.75 0.22 0.02 1.96 18.25 Poultry Litter 4,637 27.40 27.22 3.72 2.69 0.33 15.70 23.10 Whole Tree Chip 5,229 38.68 32.35 3.68 0.28 0.02 0.71 24.28 Willow Energy Crop 6,044 29.13 35.61 3.60 0.33 0.02 1.33 29.98 Corn Stover 6,385 22.00 36.27 4.53 0.44 0.09 5.77 30.94 Stumpage 6,647 9.82 40.77 4.39 0.57 0.06 14.99 29.40 Ground Pallets 6,814 19.18 42.13 4.95 0.34 0.03 0.80 32.57 C&D Debris 6,939 18.77 42.91 5.11 0.36 0.06 0.88 31.91 Switchgrass 7,370 7.88 44.70 5.57 0.29 0.05 4.53 36.98 Sawdust (Dry) 7,379 11.40 45.18 5.34 0.40 0.07 2.51 35.10 RTA Wood 7,864 7.04 46.19 4.98 3.27 0.08 0.97 37.47 Wax Cardboard 10,065 14.08 42.92 7.98 0.18 0.20 1.56 33.08

Constituent MSWBituminous

CoalCarbon 27.9 72.8Hydrogen 3.7 4.8Oxygen 20.7 6.2Nirtogen 0.2 1.5Sulfur 0.1 2.2Chlorine 0.1 0Water 31.3 3.5Ash 16.0 9HHV (wet), Btu/lb 5,100 13,000(kJ/kg) (11,863) (30,238)

Analysis of MSW and RDF Compares to Bituminous CoalAnalyses, % by wt

Constituent % by wtCarbon 79.20Hydrogen 7.30Oxygen 3.10Nitrogen 0.46Sulfur 1.56Chlorine 0.29Water 1.30Ash 7.00HHV, Btu/lb 17,000(kj/kg) 39,480

Chemical Composition of Tire Derived Fuel


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Appendix B

Solid Waste Handling Facilities within 50 miles


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Solid waste facilities within 50-mile radius of Warrenton, VA


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Solid waste handling facilities – 50 mile radius from Warrenton


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Code Facility Type Name City Miles to Warrenton

Daily Volume (tons/day)

Days per Year Waste Types Accepted Tip fee

($/ton)

VA0239 C&D Waste Inert Landfill

Potomac Debris Landfill Dumfries 40 1513.64 260

Asphalt, Concrete, or Cement, C&D, MSW, Non-Friable Asbestos, Yard

Waste 50.00$


Rainwater Concrete Debris Landfill Lorton 44 212.37 312 Asphalt, Concrete, or Cement, C&D,

MSW 30.00$


Furnace Road / Lorton Debris Landfill Lorton 44 2971.82 260

Asphalt, Concrete, or Cement, C&D, MSW, Tires (Auto), Wood, Yard

Waste 242.42$

VA0016 Composting Site SWPP Ticonderoga Farms Chantilly 29 1500 260 MSW, C&D, Yard Waste, Wood,

Asphalt/Concrete/Cement 60.00$

VA0197 Industrial Facility George Ayoob Woodbridge 41 260 C&DVA0199 Industrial Facility Thornton Hill #1 Woodbridge 41 260 Dry IndustrialVA0203 Industrial Facility Hylton Enterprises Woodbridge 41 260 Dry IndustrialVA0288 Industrial Facility Abex Corp Landfill Winchester 58 260 MSW

VA0037 Landfill Fauquier County Landfill Warrenton 0 395.31 312 C&D, MSW, Yard Waste 38.00$

VA0464 Landfill Corral Farm LF Warrenton 0 243.69 312 C&D, MSW, Non-Friable Asbestos 46.00$

VA0094 Landfill Rappahannock County Landfill Washington 14 20 312 MSW, C&D, Sludge 43.00$

VA0473 Landfill I-95 Landfill Fairfax 30 1222.24 312 Friable Asbestos, MSW, Non-Friable Asbestos 55.00$

VA0058 LandfillPrince William

Sanitary Landfill & MRF

Dumfries 40 1390.6 364C&D, Cont Soil, MSW, Ash,

Recyclables, Tires (Auto), Waste Carpet Material, Yard Waste

45.00$

VA0303 LandfillUpper Occoquan Sewer Authority

Landfill Occoquan 40 260 Sludge

VA0187 Landfill Quantico Landfill Quantico 43 260 MSW

VA0101 Landfill Rappahannock Regional Landfill Stafford 44 373.96 312 C&D, Cont Soil, MSW, Ash, Yard

Waste 36.00$

VA0271 Landfill Stafford County Landfill Stafford 44 215.72 260

Animal Waste, Asphalt, Concrete, or Cement, C&D, Cont Soil, MSW,

Recyclables, Sludge, Tires (Auto), Wood, Yard Waste

42.00$

VA0744 Landfill Battlecreek Landfill Luray 47 296.64 312 C&D, MSW, Sludge, Tires (Auto), Tires (Tractor), Tires (Truck) 35.00$

VA0070 Landfill Page County Landfill Stanley 55 778.59 312C&D, Cont Soil, MSW, Non-Friable Asbestos, Ash, Recyclables, Tires

(Auto)

VA0437 Materials Recovery (MRF)

BFI / Lorton Transcyclery Lorton 44 250 260 MSW, Recyclables 14.00$

VA0450 Mixed Waste (MRF/TS) Applehouse Compactor Front Royal 36 156 MSW, Recyclables

VA0452 Transfer Station WMI Manassas Transfer Station Manassas 24 188.5 260 MSW

VA0743 Transfer Station Culpeper County Transfer Station Culpeper 27 300 312 MSW, C&D 48.00$

VA0364 Transfer Station I-66 Transfer Station Fairfax 30 2038.83 312 C&D, MSW, Tires (Auto), White Goods & Bulky Wastes, Yard Waste 55.00$


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Solid waste handling facilities – 50 miles: Total Volume

Code Facility Type Name Miles to Warrenton

Tip fee ($/ton)

Daily Volume

(tons/day)Days per Year Annual Volume

(tons)

VA0239 C&D Waste Inert Landfill Potomac Debris Landfill 40 50.00$ 1,513.64 260 393,546.40

VA0157 C&D Waste Inert Landfill Rainwater Concrete Debris Landfill 44 30.00$ 212.37 312 66,259.44

VA0160 C&D Waste Inert Landfill Furnace Road / Lorton Debris Landfill 44 242.42$ 2,971.82 260 772,673.20

VA0016 Composting Site SWPP Ticonderoga Farms 29 60.00$ 1,500.00 260 390,000.00

VA0197 Industrial Facility George Ayoob 41 260VA0199 Industrial Facility Thornton Hill #1 41 260VA0203 Industrial Facility Hylton Enterprises 41 260VA0288 Industrial Facility Abex Corp Landfill 58 260VA0037 Landfill Fauquier County Landfill 0 38.00$ 395.31 312 123,336.72VA0464 Landfill Corral Farm LF 0 46.00$ 243.69 312 76,031.28

VA0094 Landfill Rappahannock County Landfill 14 43.00$ 20.00 312 6,240.00

VA0473 Landfill I-95 Landfill 30 55.00$ 1,222.24 312 381,338.88

VA0058 Landfill Prince William Sanitary Landfill & MRF 40 45.00$ 1,390.60 364 506,178.40

VA0303 Landfill Upper Occoquan Sewer Authority Landfill 40 260 0.00

VA0187 Landfill Quantico Landfill 43 260 0.00

VA0101 Landfill Rappahannock Regional Landfill 44 36.00$ 373.96 312 116,675.52

VA0271 Landfill Stafford County Landfill 44 42.00$ 215.72 260 56,087.20VA0744 Landfill Battlecreek Landfill 47 35.00$ 296.64 312 92,551.68VA0070 Landfill Page County Landfill 55 778.59 312 242,920.08

VA0437 Materials Recovery (MRF) BFI / Lorton Transcyclery 44 14.00$ 250.00 260 65,000.00

VA0450 Mixed Waste (MRF/TS) Applehouse Compactor 36 156

VA0452 Transfer Station WMI Manassas Transfer Station 24 188.50 260 49,010.00

VA0743 Transfer Station Culpeper County Transfer Station 27 48.00$ 300.00 312 93,600.00

VA0364 Transfer Station I-66 Transfer Station 30 55.00$ 2,038.83 312 636114.96TOTAL 3,288,838.80


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Subtotals by facility type within 50 miles

**

65,000.00Landfills

Composting SitesIndustrial Facilities

1,232,479.04390,000.00

0.001,601,359.76

Facility TypeC&D Waste Inert Landfills

778,724.96

3,288,838.80

Mixed Waste Facilities

Transfer StationsTotal

0.00Materials Recovery (MRF)

Annual Volume (tons)

*Note: Tonnage from the facilities has NOT been included in the total tonnage to avoid double-counting.


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Appendix C

Ethanol Economic Analysis


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Appendix D

Power Economic Analysis


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final report draft warrenton biomass project

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