Burton English, Jamey Menard, Marie Walsh, and Kim Jensen Professor, Research Associate, Adjunct Professor, and Professo

1. ECONOMIC IMPACTS RESULTING FROM CO-FIRING BIOMASS FEEDSTOCKS IN SOUTHEASTERN UNITED STATES COAL-FIRED PLANTS Burton English, Jamey Menard, Marie Walsh, and Kim Jensen Professor, Research Associate, Adjunct Professor, and Professor, University of Tennessee.

2. BACKGROUND Acid rain damage to forests-Great Smoky Mountains higher elevations rainfall is up to 10 times as acidic as normal precipitation in the park and fog is often 100 times more acidic • Electricity from Coal • US electricity from coal-firing>50% of electricity generated • Southeast 60% from coal-firing (DOE/EIA, 2001) • Share of air emissions from coal burning • 2/3 sulfur dioxide (SO2) • 1/3 carbon dioxide (CO2) • 1/4 nitrogen oxide (NOx) • also adds particulate matter in the air • Biomass feedstocks • agriculture residues • dedicated energy crops • forest residues • urban wood wastes • wood mill wastes have lower emission levels of sulfur or sulfur compounds and can potentially reduce nitrogen oxide emissions

3. BACKGROUND • Biomass crops raised for the purposes of energy production is carbon neutral • With co-firing, rather than 100 percent biomass use, continuous supply of biomass is not as critical (Demirbas) • Credits for offsetting SOx emissions, currently priced at $100 per ton, provide an incentive for co-firing (Comer et al.) • Costs of conversion of power plants for co-firing are relatively modest, depends on % percent co-fired • Power companies also have potential to obtain marketable value through offsetting CO2 for greenhouse gas mitigation. Replacing coal (a net CO2 emitter) with biomass (a net zero CO2 emitter) offers means to reduce CO2 while maintaining operational coal generating capacity (Comer et al.)

4. BACKGROUND • DOE projects that by 2025, biomass electricity production will increase from 38 billion to 78 billion kWhs • Electricity from municipal solid waste, including waste combustion and landfill gas, is projected to increase from 22 billion to 34 billion kWhs • Factors likely to facilitate this growth include: • changing air pollution standards • potential benefits to rural economies • capacity pressures on solid waste facilities • forest fire control policies to limit the amount of understory brush

5. Study Scenarios • producing/collecting/transporting the feedstock • retrofitting the coal-fired utilities for burning the feedstock • operating co-fired utilities • coal displaced from burning the feedstock

6. Study Area • Power plants studied were associated with Southeastern Electric Reliability Council (SERC) • 8 states – AL, GA, KY, MS, NC, SC, TN, VA • Trading regions within the eight states were identified. These regions were based on the Bureau of Economic Analysis Trading Areas • Plants AL, GA, KY, MS, NC, SC, TN, VA

7. Modeling System • ORCED • dynamic electricity distribution model estimates price utilities can pay for biomass feedstocks • models the electrical system for a region by matching the supplies and demands for two seasons of a single year • ORIBAS • GIS-based transportation model • estimates delivered costs of biomass to power plant facilities Price of Feed Stock Cost and Location of Bio-based Resource Transportation Expense Location of Power plant • IMPLAN • uses input-output analysis to derive estimated economic impacts • creates a picture of a regional economy to describe flows of goods and services to and from industries and institutions

8. ORIBAS • GIS-based transportation model used to estimate the delivered costs of biomass to hypothetical power plant facilities (Graham et al., Noon et al.) • Complete road network for each state • Waste, residues, and dedicated crop feedstocks are distributed across each county for a given state • Location and level of demand for residue • Attempts to supply the bio-based feedstocks to the power plant at lowest cost

9. ORCED • Dynamic electricity distribution model estimates price utilities can pay for feedstocks • Models electrical system for region by S and D for two seasons of a single year • Supplies are defined by up to 51 plants, extensive definitions of their operations, costs, and emissions • Demands are defined by load duration curves for each season, with gradually increasing demands based on hourly demands • As amount of residues demanded increases, cost of fuel for generation increases • Coal costs at each plant vary by scenario depending on emission costs prescribed by a given scenario • A maximum price is determined for residue at the plant gate • Price then used to determine if • sufficient quantities of residue exists to • meet the amount demanded by the co-fire scenario • Each ton of SOx produced has a negative value of $142 also, there is a $2,374 per ton NOx pollutant value in addition to the low or high carbon tax

10. IMPLAN • Input-output analysis creates a picture of a regional economy to describe flows of goods and services to and from industries and institutions • Direct impacts-changes in final demand for a sector’s product • Indirect impacts-change in inter-industry purchases due to the change in final demand from the industry directly affected • Induced impacts-changes in the incomes of households and other institutions and the resulting increases/decreases in spending power as a result of the change in final demand • Impacts are estimated for • A. One-time only impact in the Construction Sector • B. Annual Operating Cost Impacts • Electrical generation • Growing/collecting of the bio-based feedstock • Transportation • Coal mining

11. A. One Time Conversion Costs • 2 % co-fire → $50/kw • 15% co-fire → $200/kw • Plant capacity x capacity factor=kilowatts produced. • Kilowatts produced x co-fire level assumed (2% or 15%) x either the $50 or $200 investment cost=total investment • Million dollar investment was proportioned through the economy and assigned to the appropriate IMPLAN industry sectors (Van Dyke) • Each ETA was then impacted with a million dollar investment for both the 2% and 15% co-firing scenarios • To determine the impact of the investment stage within an ETA, the total investment required for all power plants within the ETA expressed in millions of dollars was multiplied by the multiplier for TIO, employment, and value added

12. B. Annual Operating Costs Impacts of the change in operating costs for the facilities in the study also required the identification of the IMPLAN industry sectors to capture the change in annual costs that would occur at the power plant facility • Power Generation -IMPLAN sector representing electricity production was modified to reflect an increase in annual machinery repair expenditures, and employment compensation was increased to reflect the additional labor requirements

13. 2) Bio-based Feedstock Costs • For each of the feedstocks, costs were distributed across the appropriate IMPLAN input sectors • Non-labor costs were used to adjust the current production function of the sector most likely to provide the output

14. 2) Bio-based Feedstock Costs • A new model was created for each bio-based feedstock with adjusted production function coefficients reflecting the new activity in the economy

15. 2) Bio-based Feedstock Costs • Total industry output, employment, and value-added multipliers were then generated for each bio-based feedstock • These multipliers were multiplied by the cost of producing/collecting the feedstock that ORIBAS indicated would be used by the power plant and the economic impact that co-firing would have in the areas where the feedstock originated was estimated

16. Proprietary Income Impacts • Value paid for the bio-based feedstock was predetermined and based on the scenario characteristics • The difference between the predetermined value and the cost of growing/collecting the residue was estimated and assumed to impact the sector’s proprietary income that generated the feedstock • An impact analysis on proprietary income was conducted in each ETA. The multiplier generated times the total change in proprietary income served as an estimate of the impacts that would occur as a result of an increase in profit with in the region

17. 3) Transportation • Total transportation sector impacts were determined by summing costs of the amount transported to the facility over all trips and residue types • The result was a change in total industry output • Input-output multipliers for the BEA’s in which the power plants are located were then used to estimate the impact on the economy, the job market, and value-added

18. 4) Coal Mining • Decrease in coal use with co-firing • Decrease in final demands on coal mining sector

19. Results • Residue Use and Energy Production • Characteristics of Coal Replaced • Economic Impacts • Total Industry Output • Jobs • Value-added

20. Residue Use and Electricity Production

21. Agricultural Residues

22. Forest Residues

23. Mill Wastes

24. Switchgrass

25. Urban Wastes

26. Coal Replaced tons Sulfur % Coal Value dollars Sulfur Replaced tons Base - 2% co - fire 355,412 0.94 $12,487,292 3,344 Low Carbon, 2% co - fire 3,251,073 1.33 $91,389,091 43,160 Low Carbon, 15%co - fire 18,198,976 1.24 $525,17 7,225 225,992 High Carbon, 2% co - fire 3,251,073 1.33 $91,389,091 43,160 High Carbon, 15%co - fire 23,987,425 1.32 $678,951,258 317,708 Characteristics of Coal Replaced by Bio-Based Feedstocks

27. High Carbon 2% Low Carbon Low Carbon High Carbon Base 2% 15% 15% Total Industry Output ($1,000) Transportation $2,995 $29,862 $432,973 $27,559 $533,618 Operating $1,011 $9,231 $51,556 $9,231 $68,154 Coal Replacement ($15,512) ($110,063) ($596,173) ($110,063) ($805,137) Bio-based Feedstocks $18,854 $331,425 $1,516,413 $330,239 $2,458,748 Total Annual Impact $7,349 $260,455 $1,404,770 $256,967 $2,255,383 Investment (Non-annual) $7,577 $71,204 $1,830,102 $71,204 $2,367,249 Jobs Transportation 34.9 342.1 5,042.90 315.7 6,095.90 Operating 8 71.7 407.4 71.7 530.5 Coal Replacement -126.9 -899.6 -4,881.90 -899.6 -6,586.50 Bio-based Feedstocks 180.8 4,368.10 20,195.40 4,368.90 32,570.60 Total Annual Jobs 96.8 3,882.30 20,763.80 3,856.70 32,610.50 Investment (Non-annual) 67.8 631 19,210.40 631 24,559.10 Value Added ($1,000) Transportation $1,514 $15,042 $216,183 $13,886 $269,693 Operating $467 $4,237 $23,632 $4,237 $31,298 Coal Replacement ($7,980) ($56,193) ($304,500) ($56,193) ($411,191) Bio-based Feedstocks $9,031 $127,288 $595,140 $126,773 $941,027 Total Annual Impact $3,032 $90,375 $530,456 $88,704 $830,826 Investment (Non-annual) $3,344 $32,248 $962,418 $32,248 $1,249,153 Impacts by Sector and Scenario

28. Key Findings • 2% co-fire, some plants do find residue at lower costs than coal plus sulfur emissions costs • 15% co-fire, paying sulfur emissions cost is more economical than burning residue • Are areas now that would benefit from generating electricity using forest residues, mill wastes, and urban wastes • In fact, nearly 2,500-kilowatt hours of electricity are produced using these residues replacing 355,000 tons of coal • Each state, with the exception of Kentucky, consumes some residue

29. Key Findings • Low Carbon and High Carbon emissions cost scenarios-amount of residues consumed will significantly increase from 4 million metric dry tons (Base) to 23 (Low Carbon) and 29 (High Carbon) million metric dry tons • Estimated $1.4 to $2.2 billion impact that occurs to the Southeast Region under the 15% co-fire levels with Low Carbon and High Carbon emission cost scenarios, respectively. Concurrent with this increase in economic activity is an estimated increase of 25,000 jobs