Fuel to Burn: Economics 

of Converting Forest 

Thinnings to Energy 

Using BioMax in 

Southern Oregon 

E. M. (Ted) Bilek 

Kenneth E. Skog 

Jeremy Fried 

Glenn Christensen 

United States

Department of 

Agriculture 

Forest Service 

Forest 

Products 

Laboratory 

General 

Technical 

Report 

FPL−GTR−157 
Abstract 

Small-scale gasification plants that generate electrical energy 

from forest health thinnings may have the potential to deliver 

substantial amounts of electricity to the national grid. We 

evaluated the economic feasibility of two sizes of BioMax, a 

generator manufactured by the Community Power Corporation of Littleton, Colorado. At current avoided-cost electricity prices in Oregon, it would not be economical to operate a 

small-scale (100-kW) BioMax without a subsidy or tax 

credit, even if fuel were delivered to the plant at a forest 

landing at no cost. Given a tax credit, a 1,000-kW system 

could be operated profitably. If it were possible to sell merchantable logs (removed as part of forest health treatments) 

for an average of $175/thousand board feet, most acres on 

gentle slopes in southern Oregon would provide net operating surpluses. Most steeply sloped acres would generate 

operating deficits. If merchantable timber were sold separately, biomass from forest health thinnings on timberland in 

15 western states could potentially provide from 2.3 to 

14.3 billion kWh of electricity to the national grid. Our 

results suggest that if a forest landing is located near an 

existing power line, distributed energy generation is an 

option that may be worth considering. 

Keywords: break-even analysis, wood gasification, smalldiameter timber, forest health treatment, economic 

evaluation. 

August 2005 

Bilek, E.M. (Ted); Skog, Kenneth E.; Fried, Jeremy; Christensen, Glenn. 

2005. Fuel to burn: Economics of converting forest thinnings to energy 

using BioMax in Southern Oregon. Gen. Tech. Rep. FPL-GTR-157. 

Madison, WI: U.S. Department of Agriculture, Forest Service, 

Forest Products Laboratory. 27 p. 

A limited number of free copies of this publication are available to the 

public from the Forest Products Laboratory, One Gifford Pinchot Drive, 

Madison, WI 53726–2398. This publication is also available online at 

www.fpl.fs.fed.us. Laboratory publications are sent to hundreds 

of libraries in the United States and elsewhere. 

The Forest Products Laboratory is maintained in cooperation with the 

University of Wisconsin. 

The use of trade or firm names is for information only and does not imply 

endorsement by the U.S. Department of Agriculture of any product or 

service. In addition, the analysis presented here does not imply endorsement 

of BioMax generators or the Community Power Corporation. 

The U.S. Department of Agriculture (USDA) prohibits discrimination in all 

its programs and activities on the basis of race, color, national origin, age, 

disability, and where applicable, sex, marital status, familial status, parental 

status, religion, sexual orientation, genetic information, political beliefs, 

reprisal, or because all or a part of an individual’s income is derived from 

any public assistance program. (Not all prohibited bases apply to all programs.) Persons with disabilities who require alternative means for communication of program information (Braille, large print, audiotape, etc.) should 

contact USDA’s TARGET Center at (202) 720–2600 (voice and TDD). To 

file a complaint of discrimination, write to USDA, Director, Office of Civil 

Rights, 1400 Independence Avenue, S.W., Washington, D.C. 20250–9410, 

or call (800) 795–3272 (voice) or (202) 720–6382 (TDD). USDA is an equal 

opportunity provider and employer. 

Acknowledgments 

The authors gratefully acknowledge the assistance of Art 

Lilley, executive vice president and chief financial officer of 

Community Power Corporation (Littleton, Colorado) in 

reviewing the BioMax model. The authors also thank Richard Bergman, Richard Bain, and Mark Nechodom for their 

careful and insightful reviews. 

Contents 

Page 

Executive Summary ............................................................... i 

Background........................................................................... 1

Objectives of Analysis .......................................................... 2

BioMax Economics............................................................... 2

Avoided Costs................................................................... 3

Basic Results..................................................................... 4

Other Assumptions............................................................ 4

Sensitivity Analysis........................................................... 6

Impact of Energy Tax Credit ............................................ 8

Limitations of BioMax Analysis..................................... 10

Conclusions for Distributed Energy Economics............. 11

Timber Stand Treatment Costs and Returns in Oregon ...... 11

Treatment Prescriptions .................................................. 11

Prescription Costs ........................................................... 13

Net Operating Surpluses and Deficits 

With Sawlog Sales .......................................................... 13

Net Costs to Deliver Chips Without Sawlog Sales ......... 14

Prescription Cost Limitations.......................................... 15

Conclusions for Prescription Costs................................. 15

Potential Role of Distributed Energy Systems in 

15 Western States................................................................ 16

Magnitude and Opportunity of Problem ......................... 16

Conclusions for Role of Distributed Energy Systems..... 17

General Discussion ............................................................. 18

Literature Cited ................................................................... 18

Glossary .............................................................................. 20

Appendix—Sample Printout for 1,000-kW BioMax 

Generator ............................................................................ 21

Cover: BioMax, a 15-kW biopower system that uses highdensity biofuels to produce heat and power. Photo courtesy 

of Community Power Corporation, Littleton, Colorado.
ii 

Executive Summary 

Small-scale gasification plants that generate electrical energy 

from forest health thinnings may have the potential to deliver 

substantial amounts of electricity to the national grid. We 

modeled the economic feasibility of BioMax, a small-scale 

heat and power generator manufactured by the Community 

Power Corporation of Littleton, Colorado, for converting 

forest thinnings to energy. BioMax can run on a variety of 

biofuels, including forest residues, coconut shells, palm-nut 

shells, corncobs, and chicken litter. We evaluated the economics of distributed electricity generation using two sizes 

of BioMax, a 100-kW unit and a 1,000-kW unit. 

Our primary objectives were (1) to evaluate the economics 

of operating generators at a forest landing, specifically determining the ability of such generators to pay for delivered 

wood both without and with an energy tax credit; (2) to 

model the wood and cash flows from forest health operations 

in a selected area when a BioMax generator is included; and 

(3) to evaluate the potential impact of distributed energy 

generation on energy supplies and forest health in 15 selected western states. 

The advantage of distributed energy, i.e., locating a plant at a 

forest landing, is that transport costs for the biomass from 

the forest to a centrally located plant are avoided. These 

costs commonly range from $0.20 to $0.60/bone-dry ton 

(bdt) per mile. The disadvantage is that the excess heat 

produced does not have an obvious alternative value (e.g., to 

displace natural gas in heating buildings). 

At current avoided-cost electricity prices in Oregon and 

using a pre-tax nominal return on invested capital of just 

over 23%, it would not be economical to operate either a 

100-kW or 1,000-kW gasification plant at a forest landing 

without a subsidy or tax credit, even if fuel were delivered to 

the plant at no cost. With a Federal energy tax credit of 

$0.018/kWh, indexed for inflation, a 100-kW BioMax located at a forest landing and selling its power into the grid 

at Oregon’s weighted average avoided-cost rate of 

$0.0437/kWh would still provide a negative present value. 

Such a system would require an average electricity price of 

$0.0728/kWh and fuel delivered to the plant at no cost, or an 

additional subsidy of $14.13/bdt to break even. Given the 

same tax credit, a 1,000-kW system would have a positive 

net present value and a real after-tax internal rate of return of 

18.1%. The larger system could afford to pay up to $6.62/bdt 

for fuel at the landing while still providing its owners with 

their required rate of return on invested capital. Alternatively, if fuel was delivered to the larger plant at a forest 

landing at no cost, the plant could break even with an electricity sales price as low as $0.0345/kWh. 

Critical assumptions in this analysis included the initial plant 

purchase costs per kilowatt, the delivered fuel price, the 

required rate of return on equity capital, and the value of the 

electricity produced. Other sensitivity analyses are 

automatically calculated by varying fixed and variable operating costs, the depreciation method used, and the amount of 

financial gearing. 

Initial per-kilowatt plant purchase costs used were $2,000 

and $1,500 for the 100- and 1,000-kW plants, respectively. 

The price of fuel delivered to the landing was assumed to be 

$0. For the 100-kW plant, every $5/ton increase increased 

the break-even electricity price by just over 10%. For the 

1,000-kW plant, each $5/ton increase in fuel prices increased 

the break-even electricity price by 23%. For the 100-kW 

plant, changing the before-tax risk premium on equity capital 

by 2% changed the break-even electricity price by just over 

3%. For the 1,000-kW plant, the same change in risk premium changed the break-even electricity price by just over 

5%. Changing the sales prices for electricity had a large 

impact on the profitability of the plants and their ability to 

pay for their delivered fuel. For both sizes of plants, every 

half-cent increase in the electricity sales price enabled the 

plant to pay an additional $3.58/bdt for delivered fuel. There 

were no differences between the plants with this measure 

because conversion efficiencies were assumed to be the 

same with both sizes of plants. 

Most forest health operations will produce at least some 

larger trees. If there were insufficient larger trees to make a 

sort for sawlogs worthwhile, or if these larger trees had 

defects making them unsuitable for sawlogs, then they 

would have to be utilized for biomass only. Under such 

conditions, most forest health operations would run at a 

deficit. The size of the deficit would depend largely on the 

amount of timber that must be removed and the harvest 

costs, which would in turn depend in part on whether the 

plot is on a gentle or steep slope. Average deficits ranged 

from $1,004/acre on gentle slopes to $4,306/acre on steep 

slopes. However, if it were possible to sell merchantable 

logs (removed as part of forest health treatments) for an 

average of $175/thousand board feet, most acres on gentle 

slopes in southern Oregon would provide net operating 

surpluses. Most steeply sloped acres would generate operating deficits. 

If merchantable timber were sold separately, biomass from 

forest health thinnings on timberland in the 15 western 

states in question could potentially provide from 2.3 to 

14.3 billion kWh of electricity to the national grid per year. 

In 2000, this would have represented 4.7% to 28.9% of the 

non-hydro renewable electricity generated in the United 

States. 

Neither the 100-kW nor the 1,000-kW wood gasification 

plant is yet being produced commercially. Our results suggest that if such plants were commercially produced and if a 

forest landing were located near an existing power line, 

distributed energy generation is an option that may be worth 

considering, especially for a gasification plant with a capacity of 1,000 kW or greater. 

Fuel to Burn: Economics of Converting 

Forest Thinnings to Energy Using 

BioMax in Southern Oregon 

E.M. (Ted) Bilek, Economist

Kenneth E. Skog, Project Leader

Forest Products Laboratory, Madison, Wisconsin 

Jeremy Fried, Team Leader 

Glenn Christensen, Forester 

Pacific Northwest Research Station, Portland, Oregon 

Background 

Nearly a century of successful fire suppression has resulted 

in dense over-stocked stands prone to catastrophic wildfires. 

Approximately 190 million acres (77 million ha) of Federally managed land is at risk of catastrophic fire in the near 

future (U.S. Congress 2003). Across all land ownerships, 

more than 70 million acres (28 million ha) is at risk for 

higher than normal mortality from insect infestation and 

disease, which in turn increases the risk of wildfire and 

results in watershed degradation, changes species diversity 

and productivity, diminishes fish and wildlife habitat, and 

decreases timber values. 

Uses need to be found for woody material removed from the 

forest to reduce the risk of wildfire. One option is to burn the 

wood for energy. Another is to convert the wood into a lowvalue commodity. However, a problem accompanies these 

options: the cost of transporting wood chips from the forest 

to the mill. Haul rates range from $0.20 to $0.60 per bone 

dry ton (bdt) per mile (1.6 km), depending on truck configuration, travel speed, and payload factors (Rummer and others 

2003). Hauling costs determine the economically viable 

distance between the forest treatment site and a processing 

facility. 

Transport costs alone may be higher than the value of the 

chips. If the chips are worth $20/bdt at an energy plant, then 

at most they could be shipped only from 33 miles (54 km) at 

$0.60/bdt/mile shipping cost to 100 miles (161 km) at 

$0.20/bdt/mile shipping cost, assuming that transport costs 

alone would be recovered. (For example, $20/bdt per 

$0.60/bdt per bdt mile = 33 miles.) A conventional rule of 

thumb is that biomass for energy can be economically 

gathered only within a 50-mile (80-km) radius from the 

combustion site (EIA 1998). 

One way around the problem of delivering chips to a distant 

plant is to eliminate the transport cost. If the chips could be 

utilized on a forest landing (e.g., in a power generator), the 

total cost of biomass removal would consist only of 

harvesting and delivery to a landing. 

Small-scale power generators are being developed by a 

number of companies, which include Carbona Corporation 

(Atlanta, Georgia), Community Power Corporation (Littleton, Colorado), External Power (Indianapolis, Indiana), and 

Flex Energies, Inc. (Mission Viejo, California). BioMax is 

an example of a small-scale heat and power generator manufactured by the Community Power Corporation. BioMax 

units can run on a variety of biofuels, including forest residues, coconut shells, palm-nut shells, corncobs, and chicken 

litter. The systems can range in size from 5 kW for homepower applications to as large as 200 kW for small industrial 

applications (Community Power Corporation 2002a). 

In a demonstration project at the Tsemeta Forestry Regeneration Complex, which is owned and operated by the Hoopa 

Valley Indian Tribe in California, a small BioMax system 

converted three different forms of forest residue fuels to 

energy and heat. In addition, the generator has delivered 

power to the Pacific Gas & Electric grid (Community Power 

Corporation 2002b). 
2 

But do the BioMax units make financial sense? What, if any, 

is the potential of distributed energy production to contribute 

to the fuels reduction problem? And under what conditions 

might it be economically feasible to locate a BioMax generator on a forest landing and eliminate the added cost to 

transport chips to a distant plant? 

Objectives of Analysis 

The objectives of our analysis of two BioMax units, 

100- and 1,000-kW generators, were as follows: 

• to determine the total subsidy required to operate the 

generators or the total profit gained, 

• to compare the economics of operating the generators at a 

forest landing, 

• to evaluate the impact of a potential energy tax credit on 

the economics of such a system, 

• to determine the area of forest that could be treated to 

provide fuel for each size of BioMax generator, 

• to determine the maximum amount that potential BioMax 

owners could afford to pay for delivered fuel, 

• given three different silvicultural prescription options in a 

given region, to estimate the cost for fuel from forest thinnings delivered to a BioMax generator on a forest landing, 

• to estimate the potential impact of distributed energy 

generation located on a forest landing on energy supplies 

in the western United States, and 

• to evaluate the potential role of distributed energy generation in ameliorating forest health problems in the western 

United States. 

Our analysis was threefold: (1) evaluation of the economics 

of distributed electricity generation using a BioMax unit; 

(2) assessment of timber stand treatment costs and returns in 

relationship to delivered quantities and costs of biomass fuel 

to landings in southern Oregon forests; and (3) analysis of 

the potential role of a distributed energy system on a forest 

landing in the utilization of unwanted biomass in 15 

western states. 

BioMax Economics 

A bio-powered distributed energy system produced by the 

Community Power Corporation was used as an example of a 

distributed energy system that might be used to effectively 

dispose of surplus wood. The unit dries and gasifies wood 

chips. It produces electricity by burning the producer gas in 

an internal combustion engine. Heat and shaft power are also 

produced. The BioMax generator is shown on the cover and 

basic specifications are listed in Table 1. 

A spreadsheet model was constructed to analyze the financial feasibility of two possible BioMax systems. A copy of 

the spreadsheet is available on the Forest Products Laboratory website as part of this report (www.fpl.fs.fed.us). 

The spreadsheet calculates before- and after-tax net present 

values (NPVs) and internal rates of return (IRRs), all in 

nominal terms, which include inflation, and in real terms,

Table 1—Specifications for BioMax generator 

Fully automatic startup, operation, and shutdown Electrical power: 5- to 50-kW modules 

Microprocessor-based control system Thermal power: 50,000 to 500,000 Btu/h 

Co-Gen (CHP) power modules Footprint: 5 by 5 m 

Non-condensing system, dry gas clean-up Weight: 1,500 kg 

No liquid effluents, no toxic wastes Gas: LHV 5 mg/m3 <5 ppm tars/particulates 

Combined heat and power Fuel conversion: ~1.5 kg wood/kWh 

Able to use a variety of woody biomass fuels (e.g., wood chips, 

pellets & scraps, nutshells) 

Gas composition: (~)O2 0%, H2 20%, 

CO 20%, CO2 7%, CH4 2%; balance N2

Optional automatic dryer/feeder Turndown ratio: >10:1 

Designed for high-volume, low-cost manufacture Full cold starting on wood gas: ~15 min 

Trailer or skid-mounted, simple installation Dispatchable power within 30 s 

Source: Community Power Corporation. www.gocpc.com/products/BioMax%20Spec%20Sheet.PDF 
3

which do not include inflation. In addition, it automatically 

calculates the break-even electricity sales price. The model 

also calculates either the break-even fuel charge (extra 

amount owners could afford to pay for fuel) or the additional 

fuel subsidy required to provide the owners with their required after-tax IRR. 

All break-even calculations include the owners’ required 

return on investment. In other words, at each of these breakeven amounts (such as for fuel subsidies, fuel charges, electricity sales prices), if everything else in the analysis is held 

constant, the after-tax real NPV will be zero and the IRR 

will exactly equal the owners’ required alternative rate of 

return. 

Although current BioMax units are in the 15- to 50-kW 

range, such units would be too small to make much of an 

impact on the biomass produced in the western forests. For 

example, given the conversion of 3.3 lb (1.5 kg) of wood 

chips/kWh, fuels removals of 50 bdt/acre (112 tonnes/ha), 

and an 81.7% capacity factor, a 15-kW BioMax would 

consume the fuel from approximately 3 acres (1.2 ha)/year. 

We chose to model the economics of a 100-kW and a 

1,000-kW unit to do a preliminary evaluation of their financial feasibility and ability to contribute to a forest health 

program. A sample printout of the BioMax spreadsheet 

model for a 1,000-kW generator is included in the Appendix. 

Wood consumption and output for 100- and 1,000-kW 

BioMax generators are shown in Table 2. In terms of physical size and output, we have not assumed any economy of 

size with respect to energy efficiency and conversion. 

Avoided Costs 

Whether or not electricity generation is economic depends 

on the price of electricity and the value, if any, of thermal 

production. Locating a generator at a forest landing near a 

transmission line would eliminate chip delivery costs. However, excess thermal production (i.e., energy not used to dry 

chips) would probably not be utilized and as such would 

have no value. The only product for which revenue would be 

received would be electricity delivered to the grid. 

Disclaimer 

BioMax generators are still in their pre-commercial 

development phase. Although several demonstration units have been constructed, no 100- or 

1,000-kW units have been built. Therefore, there is 

a degree of speculation associated with the costs 

used in our analysis. Our costs and projections may 

be representative of a commercial model. However, 

we would strongly encourage anyone considering 

investment in such a facility to do a full site-specific 

engineering feasibility analysis in addition to a financial analysis using costs and benefits that are 

appropriate for that facility in the State in which it is 

to be established. The USDA Forest Service is not 

liable for losses incurred on investments made on 

the basis of information contained in this analysis. 

Under the Public Utility Regulatory Policies Act (PURPA) 

of 1978, a utility company must purchase power from an 

independent firm at the utility’s cost of production, its 

so-called “avoided costs.” Avoided costs are the prices paid 

by the utility for electricity delivered to the grid. They are 

linked closely to delivered natural gas costs. Avoided costs 

are more akin to wholesale costs. They are generally lower 

than retail rates because they do not include such costs as 

line charges and billing fees. 

Under the Oregon statute, avoided costs are defined as 

...the incremental cost to an electric utility of electric 

energy or energy and capacity that the utility would 

generate itself or purchase from another source but 

for the purchase from a qualifying facility. (Oregon 

Revised Statutes 2003) 

A qualifying facility is defined as a cogeneration or small 

power production facility that meets certain ownership, 

operating, and efficiency criteria established by the Federal 

Energy Regulatory Commission in accordance with the 

PURPA of 1978 (EIA 2001). The capacity of a qualifying 

power plant must be no greater than 80 MW and the energy 

derived from renewable resources. While there is no size 

restriction for cogeneration plants, a qualifying cogeneration 

Table 2—Summary of wood consumption and output 

for BioMax systems with 7,876 annual productive 

hours 

BioMax system 

Consumption and output 100-kW 1,000-kW 

Annual biomass consumed 

(bdt) 1,132 11,324 

Annual electricity production 

(kWh) 787,600 7,876,000

Annual thermal production 

(1,000 Btu) 3,000,000 30,000,000
4 

facility must have at least 5% of energy output dedicated to 

“useful” thermal applications (EIA 2001). For our analysis, 

we assumed that the BioMax generators may be classified as 

qualifying facilities. 

In Oregon, the current annual average standard on-peak and 

off-peak avoided-cost rates for electricity purchases from 

qualifying facilities with a capacity of 1,000 kW or less are 

$0.048 and $0.026/kWh, respectively. However, the Public 

Utility Commission of Oregon recommended that these 

rates be raised to $0.054 and $0.030/kWh, respectively 

(McNamee 2003). We used these upward-revised avoidedcost rates in our analysis. On-peak hours are from 7:00 a.m. 

to 11:00 p.m., Monday through Friday. 

We assumed that it would be possible to produce electricity 

with the BioMax units for 20 h/day, 358 days/year, resulting 

in a utilization rate of 81.7%. Using this rate and time produces a weighted average electricity avoided-cost rate of 

$0.0437/(kWh), which we used for our analysis. 

Basic Results 

The basic results from our analysis are shown in Table 3. 

The data in Table 3 indicates that neither unit is financially 

feasible. The cash flows for the 100-kW unit are so poor that 

the IRR values are undefined. Both facilities have negative 

NPVs, and both have break-even electricity prices higher 

than Oregon’s on-peak avoided cost. Neither unit comes 

close to the off-peak avoided cost.1

 Neither unit can produce 

electricity at an average price of $0.0437/kWh, the average 

avoided cost in Oregon. 

Unless the thermal output is worth something (in terms of 

heating value), both systems at forest landings would require 

subsidies or tax credits to break even, in addition to zerocost wood fuel. The 100-kW plant would require an additional subsidy of $40.06/bdt to break even and just return the 

cost of capital to its owners. The 1,000-kW system would 

require an additional $12.62/bdt subsidy. Thermal output is 

not likely to have much value at forest landings. 

Other Assumptions 

Many assumptions we used were common to both the 100- 

and 1,000-kW units: 

 

1

 Break-even prices or values occur when the after-tax net 

present value (NPV) is zero, if all other assumptions are held 

constant. In the example given, the break-even electricity 

price is the price the BioMax would have to receive to give 

the required rate of return to its owners, if all other assumptions were held constant (e.g., delivered fuel cost of zero, no 

value for thermal output). 

• Expected before-tax nominal risk premium on invested 

capital, 20% (in addition to annual bank deposit 

interest rate) 

• Federal energy tax credit, $0/kWh 

• Fuel consumption subsidy, $0/bdt 

• Plant life, 10 years with $0 salvage 

• Repairs and maintenance, 50% of straight-line depreciation over economic life of asset 

• Variable labor cost, $0.3333/h for 100-kW BioMax and 

$3.333/h for 1,000-kW BioMax 

• Periodic consumables cost, $0.00142 kWh 

• Fuel conversion, 3.3 lb (1.5 kg)/kWh 

• Combined Federal and State tax rate, 33% 

• ad valorem (property) tax mill rate, 0% 

• Special first-year depreciation allowance, 30%2

• Depreciation method, diminishing value under general 

depreciation system (IRS 2003) 

 

2

 See IRS (2003) for detailed information on depreciation 

allowances. Special allowances are permitted if the assets are 

used on Indian reservations or in Special Enterprise Zones. 

We did not incorporate special allowances into our analysis. 

Table 3—Summary economics for BioMax systems 

with no energy tax credita

BioMax system 

Economics 100-kW 1,000-kW 

After-tax NPV b

 ($151,102) ($476,163)

After-tax IRR (real) Undefined −1.6% 

After-tax IRR (nominal) Undefined 1.3% 

Break-even electricity price 

($/kWh)a

 $0.0996 $0.0614 

Surplus available (subsidy 

required) ($/bdt)a

 ($40.06) ($12.62) 

a

Delivered fuel cost of $0/bdt, no thermal value, and 

 avoided-cost electricity sales price of $0.0437/kWh. bAt pre-tax nominal risk premium of 20% over bank interest 

 rate of 3%. 
5

The nominal risk premium on invested capital expected 

before taxes is a risk premium that is added to the bank 

deposit (safe) interest rate. This premium may be on the low 

side of what is expected in the power industry. For example, 

a large California organization expects 28% to 35% return 

on investment in this industry (personal communication, 

Mark Nechodorn, USDA Forest Service, Pacific Southwest 

Research Station). 

Since the electricity generated by BioMax uses a modified 

internal combustion engine, major plant refitting will probably be necessary after 10 years. Haq (2002) assumed a project life of 30 years for the cost and performance of biomass 

integrated gasification combined-cycle generating plants. 

However, the capacity of the plant he analyzed was 

100 MW. Our decision to use a 10-year life is conservative; 

allowing for a longer life would improve the economics. We 

test for this in the sensitivity analysis. 

In regard to repairs and maintenance, the Department of 

Energy (1997) reported annual fixed maintenance and labor 

costs of $36.5/kW for a 75-MW plant in 1997. In 2000, this 

cost decreased to $30.47/kW. Adjusted for the initial capital 

value of the plant and expressed as a percentage of straightline depreciation over the economic life (30 years) of the 

assets results in repairs and maintenance percentages of 

54.4% and 48.3% of straight-line depreciation for the 

100- and 1,000-kW units, respectively. 

Labor charges are in addition to repairs and maintenance 

costs. The Department of Energy (1997) used a variable 

operating cost for labor of $0.0034/kWh for a 75-MW gasification-based biomass plant. We assumed that neither BioMax unit would require dedicated labor. Both units would be 

monitored by workers already performing other tasks, so the 

marginal cost of labor would be low. Adjusting the Department of Energy value for inflation using the consumer price 

index (CPI) resulted in $0.0040/kWh for 2004. 

The model is structured so that a single hourly labor rate is 

entered. This single rate is applied to the scheduled annual 

operating time, even if a worker would not be present and 

doing BioMax-related work for that entire time. Multiplying 

$0.0040/kWh by the plant output and dividing by the scheduled operating hours results in an hourly labor charge of 

$0.3333 for the 100-kW unit and $3.333 for the 1,000-kW 

unit. These rates mean that labor cost amounted to 9% of 

total cost for both units. 

The Department of Energy (1997) used a variable consumables cost of $0.0012/kWh (1997 dollars) in its base case for 

a gasification-based 75-MW biomass plant. We used the CPI 

to update this figure for inflation, resulting in a value of 

$0.00142/kWh for 2004. 

In our analysis, we used diminishing value depreciation at a 

rate of 150% because this provided the most favorable financial outcome, assuming that the BioMax is not the sole 

revenue source of the firm. We also used a special first-year 

depreciation allowance of 30%.3

 However, because of the 

capital value of the assets, we did not allow for any section 179 deductions.4

 While our model allows use of alternative depreciation schedules, we do not present those results 

here. We assumed that the assets would be classified under 

IRS category 49.15 for an electric utility combustion turbine 

production plant (see A Question of Depreciation, page 7). 

The main difference between the 100- and 1,000-kW units is 

our assumption regarding installed delivery price. We assumed that the 100-kW unit would cost $2,000/kW and the 

1,000-kW unit would cost $1,500/kW as a result of economies of size relating to the construction of a larger unit. 

Increased efficiency in fuel conversion with a larger unit 

would further exacerbate the differences in the economics of 

the two units. 

We also assumed some economies of size with respect 

to general administration costs regarding the two units; 

we allowed $5,000/year for the 100-kW BioMax and 

$10,000/year for the 1,000-kW BioMax. General administration costs accounted for 7% of total costs for the 100 kW 

unit and 2% of total costs for the 1,000-kW unit. 

We ran our models with a delivered fuel cost of $0/bdt so 

that we could see how much (if anything) operators of BioMax generators could afford to pay for fuel, given the other 

assumptions. Any surplus represents cash that could go 

towards paying for fuel and forest health operations. Any 

deficit represents an additional subsidy that the owners 

would need in order to make their specified return on 

investment. 

 

3

 The special first-year depreciation allowance was put in 

place by the Job Creation and Worker Assistance Act of 

2002. It is an allowance in addition to ordinary depreciation 

and is calculated after any section 179 deduction. If taken, it 

should be 30% of the adjusted book value (i.e., purchase 

price less any section 179 deduction), unless the facility may 

be classified as Qualified Liberty Zone Property. For further 

information see IRS (2003). 

4

 Section 179 of the Internal Revenue Code allows investors 

the option to recover all or part of the cost of certain qualifying property by deducting it in the year the property is 

placed in service. In effect, it allows an investor to treat an 

asset purchase as an immediate expense. The IRS refers to 

this as a “section 179 deduction.” There are limitations and 

restrictions on this deduction. For more information, see IRS 

(2003). 
6 

Sensitivity Analysis 

As with any economic analysis, the numbers presented in the 

results depend on the assumptions. Because the units we are 

modeling are not currently being produced, our results are 

based on many costs that are informed guesses. However, 

the sensitivity analysis does indicate which variables will 

be critical to monitor to keep the project economics favorable. The pre-tax cost breakdowns in Figure 1 indicate 

which variables cause the greatest impact on financial 

outputs. 

Ownership costs make up a significant proportion of the 

total pre-tax costs of both units. The ability of either unit to 

pay for its delivered fuel is inversely related to initial capital 

costs, as shown in Figure 2. Negative numbers on the y-axis 

represent surplus funds that could go towards paying for 

delivered fuel. 

Figure 2 shows that initial capital costs would have to decline to nearly $1,000/kW for even the 1,000-kW BioMax to 

be able to operate without additional subsidies. At $900/kW, 

the 100-kW unit would still require an additional operating 

subsidy of $11.52/bdt to provide its owners with a required 

nominal pre-tax rate of return of 23.04%. 

The negative number for the 1,000-kW BioMax at a capital 

cost of $900/kW indicates that at this capital cost, operators 

would be able to afford to pay $2.95/bdt for fuel and still be 

able to pay the required rate of return to owners. At any 

given identical capital cost, the difference between the two 

units is $14.46/bdt. That is, operators of the larger unit could 

afford to pay an additional $14.46/bdt while achieving the 

same rate of return. 

The owners’ required risk premium on investment capital 

can be a key variable in determining the financial feasibility 

of a potential investment. The model is constructed so that 

the owners’ required risk premium is in addition to the bank 

savings rate. Our base case uses a risk premium of 20% in 

addition to a bank savings APR of 3%. Figure 3 shows 

premiums of 2% to 28% over the bank rate and their impact 

on the break-even fuel cost for both BioMax units. 

Figure 3 illustrates that even with a risk premium of just 2% 

above a bank deposit rate (assumed to be 3%), both BioMax 

units would still require subsidies to operate at a forest landing and sell electricity to the grid at the avoided-cost rate of 

$0.0437/kWh. 

The avoided-cost rate itself is a major variable with respect 

to the economics of the BioMax units. Sensitivity to electricity prices is shown in Figure 4. Electricity prices would have 

to climb above $0.0996/kWh for the 100-kWh unit and 

above $0.0614/kWh for the 1,000-kW unit before the operators could afford to pay for delivered fuel. Below these 

prices, the operation would require additional subsidies if the 

owners were to achieve a required rate of return of 20% over 

the bank deposit rate. 

Figure 1—Pre-tax cost breakdowns for 100- and 1,000-kW BioMax generators. 
7

A Question of Depreciation 

How should BioMax generators be depreciated? 

It depends on how the assets are classified. It also 

depends on what depreciation method is chosen, 

diminishing value or straight line, and which depreciation system is used: the general depreciation 

system (GDS), which is based on the modified 

accelerated depreciation system (MACRS), or the 

alternative depreciation system (ADS), which 

provides for a longer depreciable life. How the unit 

is classified depends on its size and the method 

of electricity generation. 

If the total capacity of the unit is in excess of 

500 kW, it may be classified under asset class 

00.4, Industrial Steam and Electric Generation 

and/or Distribution Systems, which gives the 

following recovery periods: 

GDS (MACRS): 15 years ADS: 22 years 

Alternatively, depending on how the electricity is 

generated, the unit may be classified under 49.13, 

Electric Utility Steam Production Plant, with the 

following recovery periods: 

 GDS (MACRS): 20 years ADS: 28 years 

If classified under 49.15 Electric Utility Combustion 

Turbine Production Plant, the recovery periods are 

as follows: 

 GDS (MACRS): 15 years ADS: 20 years 

It may be worthwhile to depreciate the gasification 

unit and the combustion unit separately. If so, the 

gasifier may be classified under 49.5, Waste Reduction and Resource Recovery Plants, with the 

following recovery periods: 

 GDS (MACRS): 7 years ADS: 10 years 

Source: IRS (2003). 

Figure 2—Sensitivity to initial capital cost given no 

energy tax credit: break-even subsidies required 

(surplus available) for 100-and 1,000-kW BioMax units 

assuming avoided-cost electricity rate of $0.04437/kWh. 

Figure 3—Sensitivity to before-tax risk premiums: 

break-even fuel subsidy for 100- and 1,000-kW BioMax 

units assuming no energy tax credit and electricity price 

of $0.0437/kWh. 

Figure 4—Sensitivity to delivered electricity prices 

assuming no energy tax credit: break-even fuel subsidy 

(surplus) for 100- and 1,000-kW BioMax units. 

(200)

(150)

(100)

(50)

0

50

100

.02 .04 .06 .08 .10 .12 .14 .16 .18 .20 .22 .24 .26 

Electricity sales price ($/kWh)

Break-even fuel subsidy 

(surplus) ($/bdt)

100 kW 

1000 kW 

Difference = $27.44/bdt 

(10)

0

10

20

30

40

50

900 

1,000 

1,100 

1,200 

1,300 1,400 

1,500 1,600 1,700 

1,800 

1,900 2,000 2,100 

Break-even subsidy required 

(available surplus) ($/bdt) 

100 kW

1000 kW

Difference = $14.46/bdt 

Initial capital cost ($/kW) 

0

10

20

30

40

50

60

2 4 6 8 10 12 14 16 18 20 22 24 26 28

Before-tax risk premium (%)

100 kW

1000 kW

Difference =

$22.80-$29.83/bdt

Break-even subsidy required 

(available surplus) ($/bdt) 
8 

We also assumed an economic life of 10 years for both units. 

In a sensitivity analysis, we tested for economic lives of 

15 and 22 years, the same as the depreciation lives under the 

accelerated and alternative Internal Revenue Service schedules (IRS 2003), respectively. These longer lives improve 

the economics, but tax credits or other subsidies are still 

needed. The results for the 100- and 1,000-kW BioMax units 

are shown in Figure 5. 

Without an energy tax credit, additional subsidies are required (in addition to zero-cost fuel) for both plants to provide their required rate of return. For the 100-kW unit, the 

subsidy drops to $23.25/bdt for a plant life of 22 years and 

for the 1,000-kW unit, the subsidy drops to $0.86/bdt 

(Fig. 5). 

While using a longer economic life does make the returns 

look better, if a plant operates longer, there may be some 

additional maintenance costs or major replacement costs that 

are not included in this analysis. 

All the calculations in the sensitivity analysis indicate that 

unless an energy tax credit or some other type of operating 

subsidy were available, neither the 100-kW nor 1,000-kW 

BioMax generator at a forest landing would probably be 

economic unless electricity prices were roughly 40% to 

130% higher than the current avoided-cost rate in Oregon. 

Impact of Energy Tax Credit 

The disposal of biomass in high-efficiency burners (e.g., for 

power generation) may provide environmental benefits when 

compared with alternative disposal methods. Morris (1999) 

quantified emissions when biomass is used for energy compared with emission that would occur with open burning, 

landfill disposal, immediate or delayed composting, spreading, or forest accumulation. In most cases, controlled 

combustion in electrical generation plants provides lower 

emissions than do the alternatives. Open burning produces 

massive smoke emissions containing particulates and other 

pollutants. Disposition of biomass in landfill reduces landfill 

capacity and ultimately leads to higher greenhouse gas emissions compared with that from controlled combustion. 

Allowing forests to remain overgrown can depress forest 

health and productivity, increase the risk of catastrophic 

wildfire, and degrade watershed quality. 

Using a base-case conservative analysis, Morris (1999) 

placed values (costs) on emissions and adjusted for time. He 

found that the value of controlled combustion in the United 

States is $0.114/kWh. This figure results from reductions in 

particulates, greenhouse gases, and depletion of landfill 

capacity. It does not include the value of the electricity 

produced or any benefits from rural employment, rural economic development, or security provided by distributed 

energy production. If such benefits are added to the value of 

energy production, then the production of energy with small, 

mobile generators on forest landings may be economic from 

a societal perspective as well. 

Tax credits and other subsidies may help make biomass 

energy generation systems financially viable. Federal credits 

have been available through the Renewable Energy Production Credit (REPC) and were previously available through 

the Renewable Energy Production Incentive (REPI) (U.S. 

Department of Energy 2004). For the calendar years 2002 

and 2003, both the REPC and REPI offered tax incentives or 

payments amounting to $0.018/kWh and indexed for 

inflation. 

The REPI was available to private entities subject to taxation 

that generated electricity from wind and “closed loop” biomass facilities, which grew biomass specifically for energy 

production, harvesting and converting that biomass into 

energy, and selling the resulting electricity to unrelated 

parties. 

Although the REPI formally terminated on December 31, 

2003, it was re-enacted as part of the American Jobs Creation Act of 20045

 (set to terminate on December 31, 2005), 

and was retroactively extended back to January 1, 2004 (see 

Public law 108–357, Section 710). This law modified Section 45 of the U.S. Internal Revenue Code (Title 26 or 26 

USC). Under this extension, the provisions of the tax credit 

were broadened to include open-loop biomass. Open-loop 

biomass includes mill and harvesting residues, precommercial thinnings, slash, and brush. Production may be in any 

qualified facility placed in service before January 1, 2006. 

 

5

 The American Jobs Creation Act of 2004 can be accessed 

from the Government Printing Office website at 

http://frwebgate.access.gpo.gov/cgi-bin/multidb.cgi 

Figure 5—Impact of economic life on ability of 100- and 

1,000-kW BioMax units to pay for fuel, given no energy 

tax credit. 

0 

5 

10 

15 

20 

25 

30 

35 

40 

45 

10 15 22 

100 kW

1000 kW

Additional subsidy needed ($/bdt) 

Economic life (years) 
9

Specific provisions in the law relate to phasing out this credit 

and to its applicability. Users should consult with accountants regarding their eligibility for this credit. Our purpose 

here is to analyze the impact of a $0.018/kWh tax credit on 

the economics of the BioMax gasifiers. 

Tax credits can change the cash flows and the economics of 

the gasifiers. The results with an inflation-adjusted tax credit 

of $0.018/kWh are summarized in Table 4. Despite this 

credit, the 100-kW unit at a landing would still be unable to 

provide a positive rate of return. This unit would still require 

a break-even electricity price of $0.0728/kWh, which is 

higher than the on-peak avoided-cost rate in Oregon. On the 

other hand, such a subsidy would allow the 1,000-kW unit to 

operate profitably. In addition, the surplus of $6.62/bdt could 

be used to pay for delivered fuel, and owners would still 

achieve their required rate of return. 

The sensitivity analysis graphs were adjusted to take into 

account an energy tax credit. The sensitivity to the initial 

capital cost with an energy tax credit is shown in Figure 6 

(compare to Figure 2, which shows sensitivity without tax 

credit). The energy tax credit simply shifts both sensitivity 

lines to the left. The difference between the two lines, 

$14.46/bdt, remains the same in Figures 2 and 6. Figure 6 

shows that initial capital costs would have to decline to 

about $1,200/kW for unsubsidized operation of a 100-kW 

BioMax generator. For a 1,000-kW unit, however, costs 

could rise to $1,750/kW before the cost of delivered fuel 

would be prohibitive. The negative numbers in Figure 6 (in 

lower capital cost ranges) represent available surpluses that 

could be used to pay for delivered fuel. 

Results of the sensitivity analysis are similar for other 

figures. For example, an inflation-indexed energy tax credit 

of $0.018/kWh shifts the curves for sensitivity to 

electricity sales price downwards by $19.25/bdt (compare 

Figures 4 and 7). That is, at any given electricity sales price, 

an energy tax credit of $0.018/kWh increases the ability of 

the plant to pay for fuel by $19.25/bdt. However, while the 

curves are shifted downwards, the difference between the 

cost curves of the two plants remains unchanged at 

$27.44/bdt. 

The purpose of our initial analysis was to determine how 

much (if anything) users of a BioMax-type generator could 

afford to pay for delivered fuel at a forest landing. An 

alternative question is, given a range of possible subsidies or 

fuel costs, at what price would the generated electricity have 

to be sold to pay for its costs and provide the required rate of 

Table 4—Summary economics for BioMax systems at 

inflation-adjusted energy tax credit of $0.018/kWha

BioMax system 

Economics 100-kW 1,000-kW 

After-tax NPV (at a real rate of 

12.08%) 

($78,507) $249,790 

After-tax IRR (real) (4.4%) 18.1% 

After-tax IRR (nominal) (1.6%) 21.6% 

Break-even electricity price 

($/kWh) 

$0.0728 $0.0345 

Surplus available (subsidy 

required) ($/bdt) 

($20.81) $6.62 

a

At delivered fuel cost of $0/bdt, no thermal value, and 

 avoided-cost electricity sales price of $0.0437/kWh. 

Figure 6—Sensitivity to initial capital cost given 

inflation-adjusted energy tax credit of $0.018/kWh: 

break-even subsidy required (surplus available) for 

100- and 1,000-kW BioMax units. 

Figure 7—Sensitivity to delivered electricity prices 

assuming price inflation-indexed energy tax credit of 

$0.018: break-even subsidy required (surplus available) 

for 100- and 1,000-kW BioMax units. Compared with 

values in Fig 4., values are $19.25 lower for both 100- 

and 1,000-kW plants. Difference between plants remains 

$27.44/bdt. 

(30)

(20) 

(10) 

0 

10 

20 

30 

900 1,100 1,300 1,500 1,700 1,900 2,100 

Initial capital cost ($/kW)

Break-even subsidy required 

(available surplus) ($/bdt) 

100 kW

1000 kW

Difference = $14.46/bdt

(200) 

(150) 

(100) 

(50) 

0

50

0.02 0.06 0.08 0.12 0.16 0.22 0.26 

Electricity sales price ($/kWh)

100 kW

1000 kW

Difference = $27.44/bdt

Break-even fuel subsidy 

(surplus)($/bdt)
10 

be sold to pay for its costs and provide the required rate of 

return to the plant’s owners? 

A range of fuel costs, from a subsidy of $30/bdt to a charge 

of $30/bdt, was examined with respect to its impact on 

break-even electricity prices at the landing. In Figure 8, the 

subsidies (negative numbers, in parentheses) on the y-axis 

represent additional payments to BioMax owners that they 

would require to provide a 20% risk premium for combustion of wood waste at the electricity prices on the x-axis. The 

positive numbers on the x-axis represent possible payments 

for delivered fuel at the specified electricity prices. 

Figure 8 shows that for any given fuel cost, the 100-kW unit 

requires a higher electricity sales price than does the 1,000-

kW unit to break even. The difference is slightly more than 

$0.038/kWh. For example, at a delivered fuel cost of 

$20/bdt, the 100-kW unit would require an electricity price 

of $0.101/kWh, whereas the 1,000-kW unit would require 

just $0.062/kWh. 

The sensitivity of the BioMax units to their economic life 

with no energy tax credit is shown in Figure 5. If a Federal 

energy tax credit of $0.018/kWh indexed to inflation were 

available, a 100-kW BioMax would still require an additional payment per ton ranging from $20.81/bdt for a plant 

with a 10-year economic life to $9.69/bdt for a plant with a 

22-year economic life (Fig. 9). However, operators of a 

1,000-kW BioMax could afford to pay $6.62 to $13.39/bdt 

for fuel if the unit’s economic life increased from 10 to 

22 years, respectively. 

With an energy tax credit of $0.018/kWh, the 100-kW BioMax would still require an additional operating subsidy, 

under the economic lives we examined. If the plant were to 

last 22 years, the necessary subsidy would drop to $9.69/bdt 

for a 100-kW plant. The ability of operators of a 1,000-kW 

plant to pay for fuel increases with the economic life of the 

plant. If the economic life were 22 years, operators of a 

1,000-kW plant would be able to pay $13.39/bdt for fuel. 

Limitations of BioMax Analysis 

Several assumptions in this analysis could be further 

refined: 

The capability of the harvest system matches that of the 

generator—A 100-kW BioMax unit would burn 

1,132 bdt/year and a 1,000-kW unit 11,324 bdt/year (see 

Table 2). Since a small feller–buncher and forwarder can 

produce about 15,000 bdt/year,6

 any mismatch between the 

harvesting system and the larger generator is minimal. However, a small chipper can produce about 37,500 bdt/year.7

This means that a single chipper has to feed several units, a 

market is needed for the excess chips produced, or the chipper will operate at only one-third its capacity. If the latter is 

the case, then the harvesting and chipping costs will probably be higher than those specified in the following text. 

The analysis assumes no value for waste heat produced—

In reality, some heat would be used to dry the chips to 15% 

moisture content before combustion. However, the excess 

heat from a plant on a forest landing would have no value. If 

the generator were set up in a place where the surplus heat 

 

6

 Assumes a small feller and forwarder can supply 5 green 

tons to a chipper every 15 min (Bob Rummer, USDA Forest 

Service, Southern Research Station, Auburn, Alabama; 

personal communication) and operates 6 h/day for 

250 days/year. This equates to 30,000 green tons or 

15,000 bdt. 

7

 Assumes a small whole-tree chipper produces about 

50 green tons/h (Todd Gustafson, Morbark Industries, personal communication). 

Figure 8—Sensitivity to fuel costs: break-even electricity 

prices for 100- and 1,000-kW BioMax units with energy 

tax credit of $0.018/kWh. Values in parentheses on x-axis 

are negative. 

Figure 9—Impact of economic life on ability of 100- 

and 1,000-kW BioMax units to pay for fuel, given 

inflation-adjusted energy tax credit of $0.018/kWh. 

(20)

(15)

(10)

(5)

0

5

10

15

20

25

10 15 22 

Economic life (years)

100 kW

1000 kW

Additional subsidy needed ($/bdt) 

(0.02)

0

0.02

0.04

0.06

0.08

0.10

0.12

0.14

(30)(25)(20)(15)(10) (5) 0 5 10 15 20 25 30 

Delivered fuel price ($/bdt)

100 kW

1000 kW

Difference = $0.038/kWh

Break-even electricity price ($/kWh)
11

had some positive value, then the economics of power generation would be more favorable. 

The generator would be set up on a forest landing not far 

from a pre-existing power line—Transporting the wood 

chips would entail additional costs. Alternatively, additional 

costs would be incurred if lines had to be installed to transmit generated power from the landing to the grid. 

The landing has sufficient space for the generator, chipper, and associated equipment and no additional cost is 

required for the land—Even if there were no cost for the 

land, some additional cost would be entailed in constructing 

a larger landing. Costs may also be associated with in-site 

restoration when the generator is moved. However, the 

absolute area required might be a problem (Todd Gustafson, 

Morbark Industries, Rapid River, Michigan; personal communication)..

For example, if the site required space for the 

BioMax, a 57-ft (17-m) flail chipper with a 48-ft (15-m) 

grinder, skidders, delimbers, and log makers, along with 

their associated equipment, problems may be encountered 

with the absolute size of the landing. In addition, if the 

harvesting and chipping system were not a good match with 

the generator, additional space may be required for one or 

two 48-ft (15-m) chip vans. 

The firm must be able to take advantage of tax credits in 

the year in which they are earned—Tax credits occur 

when losses are incurred. Losses may result from negative 

cash flows or from accelerated depreciation policies. Credits 

can also occur when tax credits (e.g., energy tax credits) are 

greater than taxes payable. An implicit assumption in the 

model is that tax credits may be taken in the year in which 

they are incurred. This will provide the highest rate of return. 

For this to happen, the firm must have taxable income from 

other sources against which the credit may be applied. 

If there is no taxable income from other sources, then any 

tax credits must be carried forward until a year in which 

there is taxable income. How long those credits may be 

carried forward depends on the nature of the credit. For 

Federal income taxes, capital losses may be carried forward 

until they are absorbed. Ordinary operating losses may be 

carried forward up to 20 years. The energy tax credit is 

allowed a 20-year carry-forward. 

Conclusions for Distributed 

Energy Economics 

• Preliminary economic analysis indicates that distributed 

energy systems may play a role in the disposition of wood 

waste generated from forest health treatments. However, 

given our base case numbers, without tax credits, neither 

system analyzed could be justified on financial grounds 

alone, even with no fuel cost. Initial capital costs would 

have to be lower than those we used, thermal output 

would have to have some positive value, avoided-cost 

electricity rates would have to be higher, or tax credits or 

other subsidies would need to be available to make such 

systems financially feasible. 

• Economies of scale associated with larger generators will 

probably make such units able to produce electricity at a 

lower cost per kilowatt-hour. 

• Morris (1999) justified a subsidy of $0.114/kWh on environmental grounds. Current legislation allows a tax credit 

of $0.018/kWh. Using our cost assumptions and this credit 

makes a 1,000-kW BioMax a financially justifiable investment. In addition, payment for fuel of up to $6.62/bdt 

would permit a nominal pre-tax rate of return of 23%. 

• Smaller systems (<100 kW) would probably require much 

larger operating subsidies, in addition to fuel delivered at 

no cost, to make them viable economically. 

• If the waste heat could be utilized, the economics of the 

systems might be more favorable. However, the benefits 

would have to be balanced against the possible costs of 

transporting the fuel to a point where the waste heat would 

have a positive value, rather than utilizing the fuel directly 

on the forest landing. 

Timber Stand Treatment Costs 

and Returns in Oregon 

Treatment Prescriptions 

To determine probable per acre overall costs of an integrated 

thinning and biomass combustion program, three silvicultural prescriptions based on mechanical treatments and 

removal of thinnings from overstocked stands were simulated using the Forest Vegetation Simulator. The simulations 

were conducted using data from 1,542 plots representing 

4.1 million acres (1.7 million ha) in southern Oregon and 

along the eastern slope of the Oregon Cascades, which have 

a basal area of at least 60 ft2

/acre (13.8 m2/ha) (Fried and 

others 2003). The data were derived from the Forest Inventory and Analysis project (www.fia.fs.fed.us). The harvest 

costs were estimated by using STHARVEST (Fight and 

others 2003). 

The plots covered all ownership classes and primarily consisted of mixed conifers and pines. The plots were classified 

as “gentle” (≤40% slope) or “steep” (>40% slope) to represent the difference between ground-based and cable or skyline operations. The silvicultural prescriptions regarding the 

smaller-diameter material differed on the gentle and steep 

sites. 

The first two silvicultural prescriptions, A and C, were designed to reduce stocking and improve growth, while reducing some fuel loading in small trees. Seventy percent of the 

cut basal area for these silvicultural prescriptions is derived 

from trees 5 to 14.5 in. (127 to 368 mm) in diameter at breast 

height (dbh). The remaining removals come from trees larger 

than 14.5 in. (368 mm) dbh, if present. If larger trees are 

scarce or absent, somewhere between 70% and 100% of 
12 

the basal area removed would come from trees <14.5 in. 

(<368 mm) in diameter. 

For prescription A, the target residual basal area is 

125 ft2

/acre (28.7 m2/ha) and the maximum tree diameter to 

harvest is 21 in. (533 mm) dbh. Prescription C has a target 

residual basal area of 90 ft2

/acre (20.7 m2/ha) and also a 

maximum tree diameter to harvest of 21 in. (533 mm) dbh. If 

the maximum diameter limit is reached before the prescribed 

basal area, then the prescribed basal area is not achieved. 

Under prescriptions A and C, big trees are not cut if they are 

more than 21 in. (533 mm) dbh. 

Prescription H was designed to be more aggressive in reducing fuel loading, removing ladder fuels, and creating a more 

fire-resistant stand. Trees are removed from the smallest 

diameter classes first, until the target residual basal area of 

60 ft2

/acre (13.8 m2/ha) is met. In case studies on the Okanogan and Freemont forests, Mason and others (2003) found 

that the most overall effective treatment was to thin ponderosa pine and western larch to a basal area of 45 ft2

/acre 

(10 m2

/ha). Prescription H has no upper diameter limit on 

harvested trees. 

After running the simulations, we discarded plots on which 

less than 300 ft3

/acre (21 m3/ha) of stock would be removed, 

believing that such plots would probably not be treated 

because of the large fixed costs involved in transporting 

equipment to the sites. This left a total of 1,274 plots representing 3.4 million acres (1.4 million ha). Of this, 2.8 million 

acres (1.1 million ha) (82%) are on gentle terrain and 

622,000 acres (252,000 ha) (18%) are on steep terrain. 

The output from the Forest Vegetation Simulator is expressed in terms of cubic feet of wood harvested. This is 

divided into biomass volume and merchantable volume. We 

assumed that biomass volume would be chipped. We also 

assumed that merchantable volume could be sold as sawlogs. 

One difficulty is that prices in the market are generally expressed in terms of thousand board feet for lumber and bone 

dry tons for chips. We converted the Forest Vegetation 

Simulator output using the following factors: 

• Sawlog conversion: 1 ft3

 = 6.07 board feet (derived from 

conversion of 1,000 board ft to 164.8 ft3

 (Haynes 1990)) 

• Chip conversion: 1,000 ft3 = 13.445 bdt 

The resulting harvest volumes are shown in Table 5 by slope 

and prescription. 

We used a density of 53.78 lb/ft3

 (861 kg/m3) to convert 

cubic feet/acre (cubic meters/hectare) of chips to green 

tons/acre, the average density from harvested trees for all 

plots. To convert green tons to bone dry tons (bdt), we multiplied by 0.5, assuming a 50% moisture content. The result 

is 26.89 lb/ft3

 (431 kg/m3) bdt. To check the reasonableness 

of our conversion factor, we referred to the 1989 RPA 

(Haynes 1990), which converts softwood at 35 lb/ft3

 (561 

kg/m3

) air dry tons. Assuming 20% air-dry moisture content, 

this becomes 29.17 lb/ft3

 (467 kg/m3) bone dry. This is 

within 10% of the 26.89 lb/ft3

 (431 kg/m3) that we used. 

Using our conversion, 1,000 ft3

 = (26.89)(1000/2000) = 

13.445 bdt. 

As expected, the largest average volume of trees is removed 

under prescription H. On gentle slopes, nearly half again as 

much volume per acre is removed under prescription H; on 

steep slopes, nearly 70% as much volume is removed under 

prescription H. Much of this material would be merchantable. On gentle slopes, merchantable volume represents just 

over two-thirds the total biomass removed in prescriptions A 

and C and three-fourths of the total biomass removed in 

prescription H. On steep slopes, merchantable volume represents 93% to 95% of the total volume removed. 

Treatment Prescriptions 

For all prescriptions: 

• Check if sites meet target residual basal area of 

125 ft2/acre (28.7 m2/ha) for prescription A, 

90 ft2/acre (20.7 m2/ha) for C, and 60 ft2/acre 

(13.8 m2/ha) for H. 

• For trees <3.5 in. (<89 mm) dbh, fell all trees, cut 

in two pieces, and leave on site. 

• For trees 3.5 to 5.5 in. (89 to 140 mm) dbh, cut all 

trees: 

 • On gentle slopes (≤40%), remove and chip 

 at landing. 

 • On steep slopes (>40%), cut and scatter all 

 3.5- to 5.5-in. (89- to 140-mm) trees on site. 

For prescriptions A and C: 

Objective: Reduction of stock 

• If site has excess basal area, cut 70% of excess 

from trees >5.5 to 14.5 in. (>89 to 368 mm) dbh 

(40% yard loss). 

• Cut remaining excess basal area over target limit 

from trees >14.5 to 21.5 in. (>368 to 546 mm) 

dbh. If basal area limit is not achieved, do not cut 

larger trees. 

For prescription H: 

Objective: Protection from fire 

• Thin from below to target residual basal area. 
13

Prescription Costs 

Prescription costs do not include the impact of possible 

revenues from log sales. Prescription costs depend in large 

part on prescription, terrain, and stocking. On gentle terrain, 

prescription costs average between $929 and $1,175/acre 

($1,175/0.4 ha), depending on the prescription. To compare 

cost distributions between treatments, we normalized the 

treatment cost data, weighting the costs in each plot by the 

number of acres represented by each plot and then dividing 

by the total treatment cost for each treatment type across all 

areas represented. The sum of the treatment cost categories 

for each treatment is 100. The resulting distributions for the 

gently and steeply sloped sites are shown in Figures 10 

and 11, respectively. 

Although sites steeply sloped are generally more expensive 

to treat than are gently sloped sites, the graphs are similar. 

Both have a long and expensive tail skewed to the right. 

These sites would probably require careful scrutiny if total 

prescription budgets were limited, although sites with the 

highest treatment costs often also have the greatest 

removals. 

Net Operating Surpluses and Deficits 

With Sawlog Sales 

Higher costs do not necessarily mean that the prescription 

will run at a deficit. The net prescription deficit or surplus 

depends on the value of the logs removed. (Surplus refers to 

revenue from sawlog sales that is greater than harvest cost. 

Deficit refers to revenue from sawlog sales that is less than 

harvest cost.) We assumed that sawlogs could be sold to a 

mill at an average value of $175/thousand board feet at the 

landing, with chips disposed of at the landing. Hartsough 

(2001) used delivered sawlog values ranging from 

$700/thousand board feet for 30-in. (762-mm) dbh 

Figure 10—Normalized histogram of prescription costs 

on gently sloped sites in southern Oregon. 

1 acre = 0.4 ha. 

Figure 11—Normalized histogram of prescription costs 

on steeply sloped plots in southern Oregon. 

Table 5—Harvest volume summary by prescription type and terrain for three 

modeled prescriptions on forestland in southern Oregon (volume/acre)a

 

Avg. biomass (chips) 

removed (bdt/acre) 

Avg. merchantable 

(logs) removed 

(thousand board 

feet/acre) 

Avg. total volume 

removedb

 (bdt/acre) 

Prescription Gentle Steep Gentle Steep Gentle Steep 

A 7.2 1.1 6.6 6.9 21.9 16.4 

C 7.1 1.1 6.8 7.9 22.1 17.9 

H 9.0 1.4 10.5 13.0 32.2 30.2 

a

Silvicultural prescriptions call for leaving smaller logs (<7 in., <178 mm) on site. 

 Gentle slopes are 0–40%, on which ground-based harvest/yarding systems may be used. 

 Steep slopes are >40%, on which cable-based harvest/yarding systems must be used. 

 1 acre = 0.4 ha. 

b

Total volume includes both biomass and merchantable volume. 

0 

5

10 

15

20

25

30

35

40

≤200 

201-400 

401-600 

601-800 

801-1,000 

1,001-1,200 

1,201-1,400 

1,401-1,600 

1,601-1,800 1,801-2,000 

>2,000 

Gross treatment cost category ($/acre)

Normalized frequency 

(out of 100) 

Treatment A, $ 938/acre 

Treatment C, $ 929/acre 

Treatment H, $1,175/acre 

Average cost

0

5

10

15

20

25

30

35

40

45

50

≤500 

501-1,000 

1,001-1,500 

1,501-2,000 2,001-2,500 2,501-3,000 3,001-3,500 3,501-4,000 4,001-4,500 4,501-5,000 

>5,000 

Normalized frequency 

(out of 100) 

Treatment A, $3,051/acre 

Treatment C, $3,174/acre 

Treatment H, $4,162/acre 

Average cost

Gross treatment cost category ($/acre)
14 

trees to $300/thousand board feet for 10-in. (254-mm) dbh 

trees. The Oregon Department of Forestry (2003) reports 

“pond values” (delivered prices) for ponderosa sawlogs in 

the Klamath National Forest of $210/thousand board feet for 

6- to 8-in. (152- to 203-mm) dbh logs to $540/thousand 

board feet for ≥22-in. (≥559-mm) logs. In the Grants Pass 

Unit, prices range from $75/thousand board feet for utility 

grade (suitable for chips) to $950/thousand board feet for 

No. 1 sawmill grade. 

Surpluses and deficits with sawlog sales, assuming that chips 

could be processed at the landing, are shown in Table 6. 

Surpluses represent net positive returns from sawlog sales. 

Full forest health prescription costs are covered, as are the 

costs of getting both the logs and chips to the landing. Deficits represent amounts that would have to be recovered by 

chip sales if the individual forest health prescriptions were to 

break even. 

Surpluses are generated on average on all three silvicultural 

prescriptions on gentle slopes. Deficits occur on steep 

slopes. That is, the projected revenue from sawlog sales 

would not cover the cost of removing the timber. While the 

averages are interesting, it is worth looking at the ranges, for 

both the gentle and steep plots. The range of the operating 

surpluses (deficits) on gentle slopes is shown in Figure 12; 

the data were normalized out of 100 so that the different 

treatment types could be directly compared. 

The graph is not normally distributed. Although prescriptions on gently sloped sites generally run at a surplus, on 

roughly 10% of the sites, the mechanical treatments we 

modeled could only be run at a deficit. In addition, a small 

proportion of prescriptions could be performed at a large 

surplus (greater than $2,500/acre ($6,178/ha)). 

These surpluses may be contrasted with the expected operating deficits that would be incurred in prescriptions on steep 

slopes (Fig. 13). Even with sawlog sales, prescriptions on 

most steep slopes could only be implemented with an operating deficit. Around 30% of the plots we simulated would 

require an operating subsidy of more than $2,000/acre 

($4,942/ha). On steep sites, only about 5% of the plots 

would incur an operating surplus under prescriptions A and 

C and 55% under prescription H. 

The number of sites that could be treated only at a deficit 

would depend in part on the value of the sawlogs at the 

landing. As sawlog value increases, the number of sites that 

could be treated only at deficit declines. This relationship is 

described for gently sloped (Fig. 12) and steep (Fig. 13) sites 

in the following text.8

For every $100 change in sawlog prices at the landing, the 

number of gently sloped sites that could be treated only at a 

deficit declines by approximately half. However, even at 

relatively high sawlog prices, around 10% of gently sloped 

sites would still require subsidies to apply any mechanical 

prescriptions that we simulated. Even at relatively high 

prices for sawlogs, a large portion (roughly 40% to 60%) of 

steep sites could be treated only at a deficit. 

Net Costs to Deliver Chips Without 

Sawlog Sales 

If markets did not exist for larger logs—i.e., if the closest 

sawmill was so far away that it would be uneconomic to haul 

the logs or if treatment volumes were so low that it would 

not be worthwhile selling the larger logs as sawlogs—then 

large logs might have to be chipped. 

Hauling costs could be avoided if any chips could be disposed of on the forest landing rather than taken to a distant 

mill. Average costs to deliver chips to a landing range from 

$43 to $46/bdt on gentle slopes and $200 to $257/bdt on 

 

8

 Historic (1965–2000) prices for saw timber sold on National Forests in the Pacific Northwest may be found in 

Warren (2002). Recent quarterly prices for stumpage sold by 

public agencies may be found in Warren (2003). Recent 

prices for logs delivered to a mill (pond value) may be obtained from the Oregon Department of Forestry, State Forests Asset Management Unit (www.odf.state.or.us). 

Table 6—Average surplus (cost) to deliver chips to landing for three 

prescriptions on southern Oregon forestland by slope classification, 

with sawlog salesa

Cost ($)/acre Cost($)/bdt of chips 

Prescription Gentle Steep Gentle Steep 

A 790 (1,753) 109 (1,601) 

C 814 (1,762) 115 (1,624) 

H 1,367 (1,775) 152 (1,289) 

a

Costs assume that all logs larger than 5.5 in. (140 mm) are sold 

 as sawlogs for average of $175/thousand board feet. 
15

steep slopes (Table 7). These costs are generally greater than 

the estimated values of biomass chips. Softwood chip prices 

for the Pacific Northwest are $27/green ton delivered 

(International Woodfiber Report 2003). This equates to 

roughly $54/bdt. However, prices for pulp chips are higher 

than those for biomass chips. Pulp chips need to be relatively 

clean for papermaking, medium density fiberboard, and 

oriented strandboard. The chips are debarked. On the other 

hand, biomass chips are generally made from whole trees 

and debarking is not necessary. The resulting prices for 

biomass chips can be as much as one-third lower than those 

for pulp chips (Peter Ince, personal communication, 2004), 

which lowers the estimated delivered value for biomass 

chips to around $36/bdt. Hartsough (2001) used a value of 

$20/bdt for delivered biomass. Rummer and others (2003) 

used $30/bdt. With delivery costs ranging from $0.20 to 

$0.60 bdt/mile ($0.60/1.6 km), it is clear that biomass chips 

cannot be economically transported very far. 

If the biomass must be removed from the site and if the 

sawlogs cannot be sold, then the costs from Table 6, plus 

any additional transport cost, would have to be recovered 

through chip sales alone if the silvicultural prescription costs 

are to break even. If sawlogs can be sold, more treatment 

costs can be recovered. 

Prescription Cost Limitations 

The prescriptions we chose were designed to provide some 

estimates of the possible magnitude of prescription costs. 

They were not chosen specifically for individual sites. 

We did not model the impact of the prescriptions on 

reduction in fire risk, nor did we attempt to optimize net 

benefits from fuel prescriptions. Such work might be performed by forest managers familiar with the sites in their 

fuel prescription plans. 

While representative of possible fuel reduction prescriptions, 

the prescriptions we modeled would not necessarily be 

considered for all the sites. An understanding of this may be 

gained by looking at the ranges in maximum and minimum 

prescription costs in Figures 14 and 15. If a site is going to 

be particularly expensive to treat, a forest manager may well 

recommend a different prescription or that the prescription 

dollars be spent on more cost-effective sites. 

Conclusions for Prescription Costs 

• Surpluses are highest or costs lowest if larger diameter 

logs can be sold for higher valued products. 

• If larger diameter logs cannot be sold for higher valued 

products because of limited markets or limited supply, average modeled costs to deliver chips to the landing range 

from $1,004 to $4,306/acre ($1,004 to $4,306/0.4 ha) or 

$40 to $219/bdt, depending on prescription and angle of 

slope (gentle or steep). 

Figure 12—Normalized histogram of operating surpluses 

on gently sloped sites in southern Oregon by prescription type with sawlog sales worth average of 

$175/thousand board feet at landing and no chip 

production. 

Figure 13—Normalized histogram of operating deficits on 

steep sites in southern Oregon by prescription type with 

sawlog sales worth average of $175/thousand board feet 

at landing and no chip production. 

Table 7—Average cost to deliver chips to landing for 

three prescriptions on FIA plots in southern Oregon 

per slope classification, without sawlog salesa

Cost ($)/acre Cost ($)/bdt of chips Prescription Gentle Steep Gentle Steep 

A (1,011) (3,128) (46) (190) 

C (1,004) (3,258) (46) (182) 

H (1,291) (4,306) (40) (142) 

a

Costs assume that all removed logs are chipped. 

0 

5 

10 

15 

20 

25 

30 

35 

40 

≤=0 

1-500 

501-1,000 

1,001-1,500 1,501-2,000 2,001-2,500 2,501-3,000 3,001-3,500 3,501-4,000 4,001-4,500 

4,501-5,000 

>5,000 

Net operating surplus category ($/acre) 

Normalized frequency 

(out of 100) 

Treatment A, $ 790/acre

Treatment C, $ 814/acre

Treatment H, $1,367/acre

Average surplus 

0 

5 

10 

15 

20 

25 

30 

35 

40 

≤-2,000 

-1,999 to -1,800 -1,799 to -1,600 

 -1,599 to -1,400 

-1,399 to -1,200 

 -1,199 to -1,000 

-999 to -800 

 -799 to -600 

 -599 to -400  -399 to -200 

-199 to 0 

>0 

Net operating deficit category ($/acre) 

Normalized frequency 

(out of 100) 

Treatment A, ($1,753)/acre

Treatment C, ($1,762)/acre

Treatment H, ($1,175)/acre

Average deficit 
16 

• If biomass woodchips need to be transported from the 

forest, transport costs can constitute a significant portion 

of total delivered fuel costs. The distance that chips can be 

economically transported will depend on chip value and 

transport cost. 

• If smaller diameter logs must be removed from the forest 

for forest health reasons, unless a mill is within an economic transport distance, it may be more cost-effective to 

chip the logs and utilize the chips on the forest landing for 

energy. 

• Presently, operating surpluses do not go back into forest 

health prescriptions, e.g., to subsidize chip disposal or forest health prescription costs on steeper sites and sites 

without larger sawlogs. If this were possible, then more 

acres could be treated for a given prescription budget. 

Potential Role of Distributed 

Energy Systems in 15 

Western States 

Magnitude and Opportunity of Problem 

In 15 western states,9 Rummer and others (2003) determined 

that mechanical treatments are required to reduce hazardous 

fuel loading on at least 28 million acres (11 million ha) of 

Condition Class 3 timberland, i.e., timberland needing mechanical fuel reduction treatment before fire can be used as a 

restorative tool. This corresponds to a land area about the 

size of Ohio. If Condition Class 2 timberland (timberland 

needing fuel reduction treatment (fire or mechanical) to 

restore ecosystem function and historical fire regimes; also a 

condition of Condition Class 2) is also included, the area 

increases to 66.9 million acres (27 million ha)—about the 

size of Colorado. If all timberland with treatment opportunities is included, the area grows to 96.9 million acres 

(39 million ha), an area a bit larger than Montana. 

Rummer and others (2003) determined that there is a wide 

range of potential recoverable volume on this “overstocked” 

western timberland, depending on assumptions about what 

lands are harvested. The breakdown between merchantable 

timber and biomass is shown in Table 8. If these volumes 

were thinned over 30 years, the increase in annual harvest 

would be 11 to 72 million bdt. To put this into perspective, 

 

9

 Arizona, California, Colorado, Idaho, Kansas, Montana, 

Nebraska, Nevada, New Mexico, North Dakota, Oregon, 

South Dakota, Utah, Washington, and Wyoming. 

Figure 14—Percentage of acres on gentle slopes 

showing operating deficits with sawlogs sold at 

landing at various prices by prescription type. 

Figure 15—Percentage of acres on steep slopes showing 

operating deficits with sawlogs sold at landing at various 

prices by prescription type. 

Table 8—Estimates of potential recovery volumes from 

thinning treatments on timberland in 15 western states 

(million bone-dry tons) 

Material 

Lower bound 

estimatea Upper bound 

estimateb 

Merchantable timber 245 1,537 

Biomass 101 617 

Total 346 2,154 

a

Lower end assumes material is recovered from 

 17.1 million acres (6.9 million ha) (i.e., 60% of high-risk 

 (Condition Class 3) areas). 

b

Upper end assumes material is recovered from 

 96.9 million acres (39 million ha) of treatable timberland. 

Source: Rummer and others (2003). 

0 

10 

20 

30 

40 

50 

60 

70 

80 

90 

72 122 172 322 

Plots with deficits (%) 

Treatment H 

Treatment A

Treatment C 

Average sawlog price at landing 

($/thousand board feet) 

0 

20 

40 

60 

80 

100 

122 222 322 422

Average sawlog price at landing 

($/thousand board feet) 

Plots with deficits (%) 

Treatment A 

Treatment C 

Treatment H 
17

the total volume of timber removed in the studied 15 western 

states in 1996 was 64 million tons.10

Assuming the lower bound estimate of 101 million bdt and 

upper bound biomass estimate of 617 million bdt (from 

Table 8) would be generated over a 30-year period, and 

given the bioenergy conversions by the BioMax generators 

(from the BioMax assumptions), the potential number of 

generators that could be fueled with that biomass is shown in 

Table 9. These generators could produce from 2,342 million 

to 14,304 million kWh of electricity (Table 9). To put these 

data into perspective, the upper bound represents 2.2% of the 

electricity sales in the 15 western states in the year 2000. 

Total electricity sales by utilities to bundled ultimate customers in these states was 664,288 million kWh in 2000 

(EIA 2000). The lower bound represents a bit more than that 

sold to the residential sector of Wyoming in the year 2000 

(2,103 million kWh). 

Annual potential revenue from power generation would 

range from $102 million to $625 million with initial capital 

investment costs from $495 million to $2.7 billion (Table 9). 

Such production would come at a cost. As noted previously, 

 

10 This number was derived by summing the figures of softwood and hardwood timber removals from table 1.10 in 

Johnson (2001) and converting them using factors from 

Howard (2003): 1,000 ft3

 of softwood = 0.0175 tons and 

1,000 ft3 of hardwood = 0.0200 tons. 

a 100-kW BioMax unit may require a subsidy in addition to 

zero-cost wood fuel as well as an energy tax credit to make it 

economic to operate at a forest landing. A 1,000-kW unit 

would probably not be able to be operated economically at a 

forest landing without an energy tax credit. With an energy 

tax credit of $0.018/kWh, operators of a 1,000-kW unit 

would probably be able to pay something for fuel delivered 

at a forest landing. 

Conclusions for Role of Distributed 

Energy Systems 

• Biomass from forest health thinnings in 15 western states 

has the potential to provide from 2 to 14 billion kWh of 

electricity to the national grid each year. The lower bound 

assumes sawlog sales from larger merchantable material. 

The upper bound assumes that all thinnings would be used 

for energy. 

• Such generation capacity would probably require an initial 

capital investment of $500 million to $3 billion. 

• For such generation to compete with existing fossil fuels 

on a cost basis, subsidies would probably be required. 

Such subsidies may be justified on the basis of the ancillary services provided by biomass power. 

• To maximize the area that is treatable by individual generators, merchantable logs should be sold separately rather 

than utilized as fuel. This would increase the number of 

acres treatable by a single generator by a factor of 

about six. 

Table 9—Basic summary statistics for BioMax generators that could be fueled with 

estimated potential biomass recovered from thinning treatments on timberland in 

15 western states, assuming merchantable timber is sold separately

Production factor 

Lower bound 

biomass estimatea Upper bound 

biomass estimateb 

100-kW BioMax generator 2,973 18,162 

1,000-kW BioMax generator 297 1,816 

Potential annual electricity generation 

(million kWh) 

2,342 14,304 

Potential annual revenue from power 

generation (at $0.0437/kWh) 

$102 million $625 million 

Approximate initial capital cost 

(at $1,500/kW) 

$495 million $2.7 billion 

a

Lower end assumes material is recovered from 17.1 million acres (6.9 million ha) 

 (i.e., 60% of high-risk (Condition Class 3) areas, from Table 3). 

 Annual biomass = 101 million bdt/30 years = 3.37 million bdt/year. 

b

Upper end assumes material is recovered from 96.9 million acres (39 million ha) 

 of treatable timberland (from Table 3). Annual biomass = 617 million bdt/30 years = 

 20.57 million bdt/year. 
18 

General Discussion 

BioMax-type generators may have a role to play in the combustion of surplus wood waste. This preliminary economic 

analysis indicates that their energy production costs are 

probably higher than current avoided costs. If the units are 

located on forest landings and given our assumptions, unless 

there is a tax credit or other operating subsidy, neither a 

100-kW nor a 1,000-kW unit would provide its owners a 

return on invested capital, which was computed to a real rate 

of 12.1% after taxes, based on a 20% pre-tax nominal risk 

premium. 

However, biomass combustion by BioMax units would help 

to ameliorate the problem of forest thinnings residue and 

would supply some power to the national grid. Whether or 

not such systems would be justifiable would in part depend 

on the costs of alternative disposal of the biomass generated 

from forest health thinnings and the policies that facilitate 

cost shifting. 

Subsidies for biomass disposal may be socially beneficial. 

Morris (1999) evaluated the value of the non-market benefits 

of U.S. biomass power. He inferred values to compare residues used for energy production with other disposal methods. Proxy values were derived for reductions in sulfur 

dioxide, nitrogen oxide, carbon dioxide, methane, volatile 

organic compounds (VOCs), particulates, carbon monoxide, 

landfill capacity, and forest productivity. The value of utilizing forest residues for energy production compared with 

alternative disposal methods was $0.114/kWh. This value 

did not include the value of the energy produced. While this 

is not a value that could be recovered in the marketplace, it 

does indicate the magnitude of the value of the non-market 

benefits of biomass energy production. 

Other factors may also favor such investments. According to 

the Energy Information Administration (EIA 1998), distributed generation may prove to be attractive in areas where it 

can defer transmission and distribution investment or improve reliability. Avoided costs and improved reliability are 

additional factors that should be considered in evaluating the 

potential for establishing distributed generation at any given 

location. 

Based on recent U.S. experiences with energy supplies, there 

would appear to be a role for such units in the overall energy 

supply grid. Certainly, the process of gasification in BioMax 

units is more efficient and contributes less to air pollution 

than does uncontrolled combustion in wildland fires. 

Given our assumptions, inflation-indexed energy tax credits 

or other operating subsidies equivalent to $0.018/kWh 

would make it economic to operate a 1,000-kW BioMax at a 

forest landing. Such a unit would even be able to contribute 

something towards its fuel costs while still providing owners 

with their required return on investment. However, even 

with this energy credit and zero-cost fuel, a 100-kW unit 

would not be economic to operate at a forest landing. 

This analysis, however, was based on generation units that 

do not currently exist. Therefore, the cost estimates are 

preliminary at best. A follow-up analysis should be conducted if such generators are actually constructed. Our 

analysis was based on averaged modeled treatment costs in 

southern Oregon for generalized prescriptions. In reality, the 

prescriptions should be site-specific; the actual costs and 

volumes could differ from the averages we used. 

Prior to the actual purchase and installation of a distributed 

energy system on a forest landing, the harvest costs and 

volumes for that location should be carefully evaluated, as 

well as the costs and potential revenues of that specific 

bioenergy generation system. As we showed on the southern 

Oregon sites, net harvest costs or revenues are highly variable, so that the economics of specific operations are also 

variable. 

Whether or not mechanical treatments can be run at an operating surplus will depend in part on whether there are markets for any larger logs that must be removed as part of the 

prescription. With log sales, most gently sloped sites will 

probably generate a surplus. However, our analysis showed 

that even with sawlog sales, most steep sites could be mechanically treated only at a deficit. 

Many sites could not be treated without a subsidy—either a 

direct subsidy or cross subsidy from profitable operations 

with sawlog sales. If surpluses could be used to subsidize 

treatments on additional sites (i.e., if cross subsidies were 

possible), then more area could be treated for a given budget. 

However, if each unit area is required to “pay its own way” 

in fuels treatments, then around 10% of gently sloped sites 

and 85% to 95% of steep sites could not be treated with 

these prescriptions and an average sawlog price at the landing of $175/thousand board feet. 

In spite of these limitations, this preliminary analysis indicates that for any given forest health prescription in which 

unmerchantable biomass must be removed, a distributed 

bioenergy generation system is an option that is at least 

worth consideration. 

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A strategic assessment of biomass and fuel reduction treatments in western states. U.S. Department of Agriculture, 

Forest Service. 18 p. 

www.fs.fed.us/research/infocenter.html. 
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U.S. Congress. 2003. Healthy Forests Restoration Act. 

H.R.1904, Section 201. http://thomas.loc.gov/cgibin/query/F?c108:7:./temp/~c1084uM6yP:e22998 

U.S. Department of Energy. 2004. Financial incentives for 

business investments in renewable energy. Energy efficiency 

and renewable energy (EREC) reference briefs. 

www.eere.energy.gov 

Warren, D.D. 2002. Harvest, employment, exports, and 

prices in Pacific Northwest forests, 1965–2000. Gen. Tech. 

Rep. PNW–GTR–547. Portland, OR: U.S. Department of 

Agriculture, Forest Service, Pacific Northwest Research 

Station. 17 p. www.fs.fed.us/pnw/pubs/gtr547.pdf 

Warren, D.D. 2003. Production, prices, employment, and 

trade in Northwest forest industries, all quarters of 2001. 

Res. Bull. PNW–RB–239. Portland, OR: U.S. Department of 

Agriculture, Forest Service, Pacific Northwest Research 

Station. 131 p. www.fs.fed.us/pnw/pubs/gtr547.pdf 

Glossary 

Alternative rate of return. Rate of return possible on next 

best alternative of same risk. Firm’s opportunity cost of 

money. Can be used to evaluate the net present value of a 

project or as a point of comparison with the internal rate of 

return. Also called discount rate. 

Avoided costs. Incremental costs of energy and/or capacity, 

except for purchase from a qualifying facility; a utility would 

incur avoided costs itself in the generation of energy or its 

purchase from another source. 

Basal area. Area of ground surface occupied by crosssection of tree taken at breast height. 

Closed loop process. Process by which power is generated 

using feedstock grown specifically for the purpose of energy 

production. 

Internal rate of return (IRR). Interest rate or discount rate 

that equates discounted present value of a project’s benefits 

with discounted present value of its costs. Rate of return 

earned when net present value of investment equals zero. 

Merchantable volume. Volume of main stem of tree between 1-ft (0.3-m) stump height and 4-in. (102-mm) top 

diameter (outside bark), including wood and bark. Common 

definitions used by FIA. 

Net present value. Value equal to present value of future 

benefits less present value of future costs when both are 

discounted at alternative rate of return. 

Public Utility Regulatory Policies Act of 1978 (PURPA). 

Measures designed to encourage conservation of energy, 

more efficient use of resources, and equitable rates; principally, retail rate reforms and new incentives for producing 

electricity by co-generators and users of renewable 

resources. 
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Appendix—Sample Printout for 1,000-kW BioMax Generator 
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