1

The Role of Biomass Energy in EPA’s Greenhouse Gas Rule

Partnership for Policy Integrity

September 1, 2014 v.4

This is a working document and subject to change. We appreciate the helpful input to this document so 

far. Further comments and input please to Mary Booth - mbooth@pfpi.net

Contents

A good news/bad news story about bioenergy and the greenhouse gas rule.........................................................2

EPA’s rule treats biomass and waste-burning as having zero CO2 emissions....................................................2

Bioenergy does not directly provide “mitigation” of emissions in the GHG rule.............................................3

EPA’s biogenic carbon accounting approach is likely to be science-based .........................................................4

What are the consequences of treating biomass and waste burning as having zero emissions?.........................5

EPA’s baseline and goal rates are skewed by the assumption that biomass is carbon neutral........................8

What is the role for bioenergy under the greenhouse gas rule? ..............................................................................9

EPA’s modeling shows almost no new biomass power development by 2030..................................................9

Why doesn’t EPA’s modeling show more biomass power development?.............................................................11

EPA’s modeling counts biomass energy emissions................................................................................................11

Biomass availability is limited.....................................................................................................................................13

Even if treated as carbon neutral, bioenergy is a costly way to “reduce” CO2 emissions............................15

EPA isn’t giving up on bioenergy ...................................................................................................................................16

Future regulation of biogenic CO2 emissions.........................................................................................................16

Could the GHG rule increase forest harvesting for biomass energy? ...................................................................18

Is “beyond the fenceline” carbon offsetting for bioenergy allowable under the GHG rule?..............................19

Appendix 1: EPA’s current and target emissions rates for states ranked by emission reduction required 

under the GHG rule........................................................................................................................................................22

Appendix 2: Technical information on CO2 from biomass energy.........................................................................23

Carbon dioxide emissions from power plants.......................................................................................................23

How much CO2 does burning wood emit?............................................................................................................23

How much CO2 does a biomass power plant emit?.............................................................................................23

Effect of biomass co-firing on coal plant CO2 emissions......................................................................................24

Treatment of biomass power as “carbon neutral”................................................................................................25

The “Biomass is carbon neutral because it would decompose anyway” argument ........................................25

The “Biomass is carbon neutral because forests take up CO2” argument.......................................................27
2

A good news/bad news story about bioenergy and the greenhouse gas rule

The EPA’s recently published Existing Source Performance Standards for greenhouse gas emissions (GHG), 

intended to address emissions from large fossil-fuel fired existing power plants, relies on four main “building 

blocks” as the Best System of Emissions Reduction (“BSER”) from which the Agency then calculates target 

2020 and 2030 state specific emissions rates for carbon dioxide emissions from the power sector. The 

proposed rule allows states to achieve their 2020 and 2030 target emissions rates (expressed as pounds of 

CO2 per megawatt-hour of electricity generated) in a variety of ways, provided they can be linked to 

reductions in existing power sector. One of the BSER building blocks is increased efficiency at existing 

coal plants, to reduce emissions of CO2 per unit energy generated. Another is increased use of “low” or 

“zero” emissions renewable energy. EPA seeks comment both on the way it has developed the target state 

specific emissions rates, and the way in which states may meet the rates.

Biomass energy – the combustion of wood and other biological materials in power plants – has been 

promoted extensively at the state level as renewable energy. However, it is well-known that per 

megawatt-hour (MWh), biomass power plants emit more CO2 than coal plants, and that co-firing biomass 

at coal plants increases CO2 emissions and decreases facility efficiency (see Appendix 2 for more details). 

Given these facts, it is important to determine how the EPA counts bioenergy emissions under the existing 

source GHG rule, and what role EPA envisions for biomass power in helping states meet target emissions 

rates. 

EPA’s rule treats biomass and waste-burning as having zero CO2 emissions

The short answer is that despite all the time and energy that EPA and others have devoted to developing a 

biogenic carbon accounting framework, EPA’s estimates of current power sector emissions, the 2012 

baseline, treats standalone biomass power plants as having zero carbon emissions, although emissions from 

biomass co-fired at coal plants are counted in state-level totals. Looking forward, the equation that EPA 

has developed to calculate state-level power-sector emissions rate goals, in which CO2 emissions are 

summed in the numerator, and power generation (as MWh) is summed in the denominator, treats 

standalone biomass power plants as contributing to power generation, but again, not to CO2 emissions 

(although the CO2 emitted by biomass co-fired at coal plants is counted), and again, biogenic municipal 

waste combustion is treated as having zero CO2 emissions. 

The one place where biomass (but not waste) emissions are counted is in EPA’s going forward modeling, 

the model runs that the Agency conducted to determine a least-cost pathway for states to achieve their 

emissions goals. There, emissions from standalone biomass plants are counted, along with emissions from 

biomass that is co-fired at fossil fueled plants.1 Table 1 summarizes how biomass and waste emissions are 

treated in these three areas of the rule. 

 

1 A previous version of this summary incorrectly stated that EPA’s IPM modeling treated biomass as having zero emissions, 

due to the incorrect assumption that EPA calculated 2012 rates and future goal rates using the same equation and 

assumptions. We regret the error. 
3

Table 1. Summary of how the GHG rule treats CO2 emissions from biomass and municipal waste. 

The following report explores these findings in more depth, and contemplates what they may mean for the 

role of biomass in the ESPS rule.

Bioenergy does not directly provide “mitigation” of emissions in the GHG rule

The objective of both the New Source Performance Standards (NSPS) and the Existing Source Performance 

Standards (ESPS, here also referred to as the “greenhouse gas rule” or “GHG rule”) is to reduce CO2

emissions from certain fossil fueled plants in the power sector. While the Agency’s NSPS rule governs

emissions from new coal and natural gas combined cycle power plants, the ESPS creates target emissions 

rates for the existing fleet. These rates, expressed for the power sector as a whole, are to be achieved not 

only by improving facility efficiency and taking other measures to control CO2 emissions at individual 

existing plants, but also by replacing existing coal-fired generation with lower-emitting existing natural gas 

plants2 and low- or zero-emissions renewable energy and nuclear power, and/or by reducing electricity 

demand. 

Importantly, neither the NSPS nor the ESPS explicitly offers biomass co-firing as a means to “reduce” 

emissions at coal plants. Most significantly, all emissions from fossil-fueled plants – even emissions from cofired biomass – are counted in EPA’s 2012 baseline emissions rates, in the equation that develops the goal 

emissions rates, and in EPA’s forward-looking modeling of how states can achieve the goal rates. This 

produces the counterintuitive result that emissions from biomass burned in conjunction with coal in the 

same boiler are counted under the rule, but emissions from a standalone wood-fired boiler sitting next to a 

coal-fired boiler will not be counted. 

To promote biomass co-firing would be counter to the first goal of the GHG rule, increased efficiency at 

coal plants, since co-firing biomass at a coal plant actually decreases facility efficiency and increases CO2

emissions per megawatt-hour. Indeed, an increased facility heat rate (the amount of energy required to 

produce electrical energy) was recently cited by Georgia Power as one reason to not convert its Plant 

Mitchell from coal to biomass.3 Likewise, EPA notes in a technical document4 for the GHG rule that, 

regarding co-firing, 

 

2 As the rule does not take into account methane leakage from natural gas, many are questioning whether the increased

deployment of natural gas under the rule might actually increase greenhouse gas emissions. 

3 Georgia Public Service Commission. Georgia Power Plant Mitchell Unit 3 Biomass Conversion Cancellation: Decision 

Review Findings. June 5, 2014. 

4 U.S. Environmental Protection Agency. Documentation for EPA Base Case v.5.13 Using the Integrated Planning Model. 

Page 5-9. 

Are CO2 emissions counted? 

2012 estimate of 

current emissions

Goal emissions rate 

equation

Modeling in support 

of goal rates

Biomass co-firing at coal plants yes yes yes

Biomass standalone facilities n o n o yes

Biogenic municipal waste n o n o n o
4

“logistics and boiler engineering considerations place limits on the extent of biomass that can be fired. The logistic 

considerations arise because it is only economic to transport biomass a limited distance from where it is grown given 

the low energy density of the fuel. In addition, the extent of storage that can be devoted at a power plant to this 

relatively low density fuel is another limiting factor. Boiler efficiency and other engineering considerations, 

largely due to the relatively higher moisture content and lower heat content of biomass compared 

to fossil fuel, also plays a role in limiting the level of co-firing.” (emphasis added)

Biomass co-firing is also costly. EPA provides a detailed treatment of the costs and logistics of biomass cofiring at coal plants, finding that even if biogenic CO2 emissions are treated as zero, the “reductions” in 

fossil fuel CO2 emissions at coal plants co-firing 10% biomass ranges from $30 - $80 per ton of CO2. EPA 

concludes:

“Replacing some coal with low levels of biomass co-firing may result in stack CO2 increases. Even if biogenic CO2

emissions are not counted as part of stack emissions, biomass co-firing is a relatively costly 

approach to CO2 reductions at existing coal steam boilers when compared to other measures such 

as heat rate improvements and re-dispatch of generation supply to other existing capacity with lower CO2 emissions 

rates.”5

While EPA has not offered biomass co-firing as means of reducing greenhouse gas emissions at coal plants, 

the Agency has stopped short of taking a firm position on bioenergy emissions, and the GHG rule, as 

currently formulated, treats biomass and biogenic waste burned at standalone plants as having zero carbon 

emissions. The consequences of this are explored in more depth below. 

EPA’s biogenic carbon accounting approach is likely to be science-based

Three years on since EPA’s deferral of regulation of bioenergy CO2, and nearly two years since the Science 

Advisory Board (SAB) panel issued its report, EPA does not appear to be very close to issuing a carbon 

accounting framework for bioenergy. As explained in this report, the ESPS, especially, suffers from the 

absence of clear guidance on biomass. 

However, there are hints that EPA is headed toward a science-based carbon accounting framework for 

biomass energy. For instance, the January 2014 draft of the NSPS acknowledges, 

“In general, the overall net atmospheric loading of CO2 resulting from the use of a biogenic feedstock by a stationary 

source will ultimately depend on the stationary source process and the type of feedstock used, as well as the 

conditions under which that feedstock is grown and harvested.” 

And,

“In its Advisory, the SAB recommended revisions to the EPA’s proposed accounting approach, and also noted that 

biomass cannot be considered carbon neutral a priori, without an evaluation of the carbon cycle effects related to 

the use of the type of biomass being considered.”6

 

5 U.S. Environmental Protection Agency. Technical Support Document for Carbon Pollution Guidelines for Existing Power 

Plants. GHG Abatement Masures, page 6-16. 

6

Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 

79 Fed. Reg. 1,430 (proposed Jan. 8, 2014) (“Proposed Rule”), page 1446. 
5

These same statements occurred in the September 2013 version of the NSPS, but the June 2014 ESPS 

indicates that EPA is still studying the issue:7

“The EPA is in the process of revising the draft framework and considering next steps, taking into account both the 

comments provided by the SAB and feedback from stakeholders. The EPA’s biogenic CO2 accounting framework is 

expected to provide important information regarding the scientific basis for assessing these biomass-derived fuels 

and their net atmospheric contribution of CO2 related to the growth, harvest and use of these fuels. This information 

should assist both states and the EPA in assessing the impact of the use of biomass fuels in reaching emission 

reduction goals in the energy sector under state plans to comply with the requirements in the emission guidelines.”

Despite these statements, however, the ESPS as currently formulated does contain the default assumption 

that biomass is carbon neutral – in contradiction from the SAB report’s clear conclusion, that

“Carbon neutrality cannot be assumed for all biomass energy a priori. There are circumstances in which biomass is 

grown, harvested and combusted in a carbon neutral fashion but carbon neutrality is not an appropriate a priori 

assumption; it is a conclusion that should be reached only after considering a particular feedstock’s production and 

consumption cycle”

8

What are the consequences of treating biomass and waste burning as having zero emissions?

By lumping bioenergy with all other renewables, and biomass and waste-burning as if they reduce emissions 

as effectively as wind and solar, EPA may be inadvertently promoting these technologies as mitigation 

measures in the GHG rule. Further, counting these emissions as zero can also introduce significant errors

into the estimate of present day power sector CO2 emissions and target emissions rates, which are likely 

to be carried forward as states attempt to meet target emissions goals. This problem is most apparent for 

those states where bioenergy and waste-burning contribute a significant share of total CO2 emissions. 

To explore this further, we used the same data as EPA, from the Agency’s Emissions and Generation 

Resource Integrated Database (eGRID), to estimate what proportion of state-level GHG emissions were 

not being included in EPA’s official totals. For the initial estimation of 2012 baseline power sector rates, 

EPA only considers power generation and emissions from a segment of the total power sector, excluding 

facility emissions from contributing to calculated 2012 state-level emissions rates on various grounds. 

Standalone biomass plants and municipal waste combustors are excluded because they are “non fossil fuel” 

units, burning less than 10% fossil fuels. EPA also excludes industrial/commercial power generators that are 

not connected to the grid,9 a set of facilities that includes a substantial number of biomass-burning units. 

Simple cycle turbine plants less than 25 MW and steam turbine plants less than 25 MW/250 MMBtu are also 

excluded.10

 

7

Environmental Protection Agency. 40 CFR Part 60: Carbon pollution emission guidelines for existing stationary sources:

electric generating units; proposed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 34925

8 United States Environmental Protection Agency. SAB review of EPA’s Accounting Framework for Biogenic CO2 Emissions 

From Stationary Sources. EPA-SAB-12-011. September 28, 2012. Washington, DC. 

(http://yosemite.epa.gov/sab/SABPRODUCT.NSF/57B7A4F1987D7F7385257A87007977F6/$File/EPA-SAB-12-011-

unsigned.pdf).

9

http://www2.epa.gov/sites/production/files/2014-06/documents/20140602-description-egrid-methodology.pdf

10 EPA makes the decision about whether a boiler’s emissions are regulated under the rule at the individual unit level, rather 

than the facility level, allowing multiple boilers at a single facility to be excluded using different justifications. For instance, in 

Maine, Verso Paper was burning natural gas in 2012 at four burners of 15 MW, 24 MW, 72 MW, and 186.8 MW. Although 
6

Table 2 provides a state-level summary of emissions from biomass- or waste-burning facilities that were 

excluded from state totals on the basis of being non-fossil fueled (states with low amounts of 

biomass/waste in this category may nonetheless have biomass/waste burning units that were excluded on 

the basis of not being connected to the grid). 

Table 2. Emissions from biomass and waste burning, versus fossil fuel emissions included by EPA in statelevel totals for 2012. 

 

these boilers are located at the same facility, the first two are excluded from regulation under the GHG rule on the basis of 

being less than 25 MW; the second two are exempted on the basis of being commercial/industrial units. 

State Biomass and waste 

emissions excluded on 

basis of being non-fossil 

fuels (tons CO2)

Total 

included 

emissions 

(tons CO2)

% increase if biomass 

and waste burning 

emissions were 

included in total

V T 519,266 2,319 22390.8%

ME 2,877,303 3,108,203 92.6%

NH 1,906,859 4,642,898 41.1%

WA 2,660,941 7,439,852 35.8%

CT 2,419,315 6,769,291 35.7%

MA 3,412,335 13,201,015 25.8%

HI 1,425,872 6,316,936 22.6%

ID 157,733 789,232 20.0%

OR 1,359,558 7,679,058 17.7%

CA 8,642,415 50,538,538 17.1%

MN 4,214,848 28,710,984 14.7%

NJ 1,801,946 13,938,132 12.9%

V A 3,447,003 28,425,400 12.1%

FL 13,226,624 121,388,920 10.9%

NY 3,774,380 36,128,451 10.4%

MD 1,565,937 20,592,993 7.6%

SC 2,825,130 37,792,258 7.5%

AL 4,188,420 75,901,923 5.5%

NC 3,126,428 61,711,952 5.1%

LA 2,253,311 49,513,590 4.6%

MI 3,102,176 71,060,733 4.4%

PA 3,576,247 116,966,573 3.1%

WI 1,191,782 43,037,386 2.8%

GA 1,176,147 65,130,319 1.8%

IN 812,960 101,827,187 0.8%

AR 278,014 40,137,961 0.7%

AZ 258,677 40,903,915 0.6%

OK 327,289 52,998,373 0.6%

UT 138,469 31,178,820 0.4%

OH 386,369 103,281,832 0.4%

TX 704,448 247,589,234 0.3%

ND 88,159 33,370,886 0.3%

KY 78,641 93,176,101 0.1%
7

Florida is the state with the most bioenergy/waste emissions excluded from its 2012 emissions total (13.2 

million tons). In terms of how CO2 from biomass and waste burning compares to reported CO2 from fossil 

fuels on a percentage basis, Vermont is the leader, but in fact biomass energy does not actually provide a 

high percentage of the power generated in that state, due to the presence of the 543 MW Vermont Yankee 

nuclear plant. 

Maine is the state where biomass makes the largest percentage contribution to both in-state power 

generation and power sector CO2 emissions. Figure 1 shows Maine’s 2012 emissions as reported in 

eGRID. “Included” emissions contribute to EPA’s baseline estimate of power sector emissions; “excluded”

categories are reported by e-GRID, but are not included in EPA’s summed total. 

Figure 1. eGRID data on 2012 CO2 emissions from the Maine power sector (tons, and percent 

contribution, corresponding to size of pie wedge). 

In Maine, four fossil-fueled plants contribute the 17% of emissions initially regulated by the GHG rule. Of 

the excluded emissions, Rumford Cogeneration (a biomass-burning plant owned by NewPage Corporation), 

contributes 1.3 million tons of CO2, 13% of eGRID’s reported emissions for the state. Another 28% of 

reported emissions are contributed by facilities burning biomass and waste where emissions have not been 

included in the total because they occur at facilities burning less than 10% fossil fuels (these are the 

“standalone” biomass and waste-burning plants). Biomass/waste burners that are not connected to the 

Emissions included 

in ESPS 2012 

baseline total
8

grid, and are therefore not included in the EPA total, contribute a further 17% of emissions; similarly, 12% 

of emissions come from fossil-fueled plants not connected to the grid. Another 25% of emissions come 

from fossil-fueled facilities excluded because they are less than 25 MW in size. Not reported at all to 

eGRID are those facilities that burn fuels solely for thermal energy. 

EPA’s baseline and goal rates are skewed by the assumption that biomass is carbon neutral

To develop goal emissions rates for states, EPA first determines each state’s baseline emissions rate from

2012 power sector data on emissions and generation. The “goal computation” technical support document 

actually presents two rates. First is the emissions rate from just the fossil fueled plants that are initially 

regulated under the rule, which in the case of Maine is derived from only four plants and is 873 lb 

CO2/MWh. The second rate adds generation from renewable energy to the denominator of fossil-fueled

rate (MWh), but still only counts CO2 from the fossil fueled plants in the numerator, treating all the 

renewable energy as having zero emissions. Maine’s rate in this case is 437 lb CO2/MWh.11 

In calculating the adjusted rate, EPA counts electricity generated by wind, solar, geothermal, biomass, 

waste, and landfill gas as reported by Energy Information Administration, but excludes power generated at 

conventional hydroelectric facilities.12 While all these technologies contribute electricity, none contribute 

CO2 in the rate equation - all biomass, waste, and landfill gas burning is treated as emitting zero CO2. The 

system essentially “runs the CO2 meter backwards” for the portion of fuels provided by biomass and 

waste-burning at any facility. This means, for instance, that while Rumford Cogeneration in Maine (featured 

in Figure 1) is exempted from regulation under the rule, the portion of electricity that the plant generates 

burning wood and paper-making wastes is credited as carbon-free, even as emissions from other fuels 

burned at the plant (like shredded tires) are unregulated by the rule. Table 3 presents the detailed 

breakdown of fuels burned at Rumford Cogeneration in 2012. 

 

11 U.S Environmental Protection Agency. Goal Computation Technical Support Document for the CAA Section 111(d) 

Emission Guidelines for Existing Power Plants Docket ID No. EPA-HQ-OAR-2013-0602. June, 2014. Page 25. 

http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-technical-documents

12 U.S Environmental Protection Agency. Alternative RE Approach Technical Support Document. 

http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-technical-documents. Table 1.3 on page 

11 is the version of the renewable energy generation totals where conventional hydroelectric power is excluded. Plugging 

these numbers in to the emissions calculation produces an emissions rate that matches the rate presented in the Goal 

Computation Document on page 25.
9

Table 3. Energy Information Administration data on fuels burned at NewPage Corporation’s Rumford 

Cogeneration plant in 2012. Electricity generated by burning the fuels highlighted in grey is credited as 

carbon-free in calculating the 2012 baseline power sector emissions rate for Maine. EPA reports total 

emissions from the plant as over 1.3 million tons in 2012. 

What is the role for bioenergy under the greenhouse gas rule? 

States have a great deal of flexibility under the GHG rule as to how they meet emissions reduction goals. 

EPA’s approach is to offer states a menu of options for reducing greenhouse gas emissions, which in 

addition to the building blocks of increased efficiency at coal plants and new renewable energy, also includes 

greater dispatch of natural gas plants and increased demand side efficiency. EPA models and projects 

potential outcomes of the rule using the Integrated Planning Model (IPM) which is designed to seek optimal, 

least cost scenarios for power sector development, given initial sets of constraints. EPA used IPM to model 

a “Base Case,” representing development of the power sector if the GHG rule is not adopted,13 and 

scenarios representing implementation of the rule with state versus regional goals and goal implementation 

over differing timeframes. 

EPA’s modeling shows almost no new biomass power development by 2030

EPA’s modeling is not prescriptive in any sense, but it does map out optimal, least cost pathways that states 

could follow. It is thus interesting that the IPM scenarios of modeling implementation of the greenhouse 

gas rule actually show very low levels of biopower sector development. This is because while EPA models

 

13 http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html

Reported Fuel Type

Physical 

Unit Label

Total Fuel 

Consumption 

Quantity

Electric Fuel 

Consumption 

Quantity

Total Fuel 

Consumption 

MMBtu

Elec Fuel 

Consumption 

MMBtu

Net Generation 

(Megawatthours)

Percent 

of Total

Bituminous Coal short tons 31,769 6,032 810,183 153,809 30,392 5%

Black Liquor short tons 715,330 137,114 8,208,219 1,573,399 311,103 50%

Distillate Fuel Oil (Diesel, 

No. 1, No. 2, and No. 4 

Fuel Oils) barrels 0 0 0 0 0 0%

Residual Fuel Oil (No. 5, 

No. 6 Fuel Oils, and 

Bunker C Fuel Oil) barrels 25,954 4,621 162,215 28,871 5,703 1%

Sludge Waste short tons 41,295 7,825 465,439 88,211 17,420 3%

Tire-derived Fuels short tons 126,205 24,182 3,912,355 749,646 148,234 24%

Wood/Wood Waste 

Solids (paper pellets, 

railroad ties, utility 

poles, wood chips, 

bark, and other wood 

waste solids) short tons 337,412 64,945 2,868,002 552,024 109,176 18%
10

existing biomass energy facilities as continuing to operate, the model excludes development of new biomass 

burning facilities as states seek to achieve emissions reductions goals. A technical document explains:14 

“1.3. RE Target Generation Methodology by Technology Type 

This section describes the methodology employed to produce target generation levels for each state by technology 

type. The RE technology types that contribute to each state’s target generation level are utility-scale solar, onshore 

wind, conventional geothermal (hydrothermal), hydropower, and select existing biopower capacity types.”

Bioenergy development under EPA’s modeling for GHG rule implementation is indeed essentially flat. As 

shown in Figure 2, biopower buildout under both the State Option 1 modeling scenario (under which GHG 

reduction targets are achieved by 2030) and State Option 2 runs (under which GHG reductions are slightly 

less aggressive than under Option 1 by the year 202015), are both lower than for the Base Case, under 

which the GHG rule is not implemented. 

Figure 2. Biopower development under the Base Case (no GHG rule) and two GHG rule implementation 

scenarios, as predicted using EPA’s IPM model. 

Data from the Energy Information Administration (EIA) reveal that the whole bioenergy industry in the U.S.

generated about 37.8 thousand gigawatt-hours (GWh) of electricity in 2012.16 Under the IPM scenarios for 

State Option 1 and State Option 2, bioenergy generation in 2030 decreases to 33 and 37 thousand GWh, 

respectively, while the Base Case generation is 53 thousand GWh in 2030.

17

Figure 3 demonstrates that EPA’s projections of biomass buildout, even under the Base Case, are also low 

relative to projections from the Energy Information Administration’s modeling. The EIA uses the National 

 

14 U.S. Environmental Protection Agency. Alternative Renewable Energy Approach Technical Support Document. Technical 

Support Document (TSD) for Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Docket ID No. EPA-HQ-OAR-2013-0602, June 2014.

15 Environmental Protection Agency. 40 CFR Part 60: Carbon pollution emission guidelines for existing stationary sources: 

electric generating units; proposed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 34931

16 Energy Information Administration. Annual Generation. State Historical Tables for 2013, December 2013.

17 These numbers are obtained by summing the “biomass” and “biomass co-firing” values on the “summary” tab of the “ssr” 

spreadsheets provided by EPA for each scenario. These are available for download at 

http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html
11

Energy Modeling System (NEMS) to develop its Annual Energy Outlook (AEO). Each year, the AEO 

“reference case” modeling shows actual energy sector development for the preceding two years, then 

forecasts future development. Forecasts can vary widely year to year. Comparing the EPA’s IPM 

projections for the GHG rule (which start in 2016) to EIA’s AEO forecasts, it can be seen that the EPA’s 

Base Case projection tracks EIA’s 2012 reference case scenario until about 2025, but shows lower capacity 

thereafter. The State Option 1 scenario is lower after about 2018 than all of EIA’s recent AEO projections. 

Figure 3. EPA’s predictions for bioenergy development contrasted with EIA’s predictions. 

Why doesn’t EPA’s modeling show more biomass power development? 

EPA’s decision to exclude new biomass power development from its forward-looking modeling is obviously 

not prescriptive, but it does reflect some realities about costs and impacts of biomass energy. 

EPA’s modeling counts biomass energy emissions 

First, EPA has counted actual stack emissions from bioenergy in its forward-looking modeling, which 

probably explains in part why little new bioenergy capacity is included, since growing the industry is 

counterproductive to reducing emissions. The modeling treats biomass but as a high-carbon fuel with 

emissions of 195 lb CO2/MMBtu,

18 a rate that translates approximately one ton of forest wood emitting 

 

18 EPA’s Integrated Planning Model (IPM) modeling files in support of the ESPS rule are available at 

http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html. The “State Option 1” zipped directory contains 

the “Proposed Clean Power Plan_Option1 State_rpe file.xls” file, which contains the CO2 emission factors (in lb/MMBtu) 

assigned to each fuel type by the model. Biomass is assigned an emissions factor of 195 lb/MMBtu, whereas municipal waste 

(and landfill gas) are assigned an emissions factor of zero.
12

one ton of CO2 when burned.19 (The modeling still treats biogenic waste burning as having zero 

emissions.) Under this scheme, any net reductions in lifecycle CO2 emissions that do occur over time (see 

Appendix 2) are a “bonus” – but the model doesn’t depend on them occurring in its determination of how 

states can meet their target goals. This is a sound modeling decision, for while it means that the modeling 

does not match EPA’s equation for determining state-level goal emissions rates, it is useful because it 

answers the questions, “What happens if under EPA’s carbon accounting framework, or due to legal 

reasons, all bioenergy emissions must be counted? Can states still achieve their renewable energy goals 

with minimal bioenergy?”

In Maine, as elsewhere, the answer is yes, with the modeling projecting a mixture of low-emissions 

renewable energy, natural gas, and high-emissions biomass to help the state to achieve its 2030 emissions 

goal (Figure 4). 

Figure 4. EPA’s optimal, least-cost projection for Maine’s power sector in 2030. The percentages (and 

size of pie wedges) refer to the proportion of power generated. 

Under the modeling scenario for Maine, biomass provides the majority of the state’s power sector CO2

emissions in 2030 (while the modeling treats biogenic municipal waste burning as zero emissions, the 

 

19 A previous version of this summary incorrectly stated that EPA’s IPM modeling treated biomass as having zero emissions, 

due to the incorrect assumption that EPA calculated 2012 rates and future goal rates using the same equation and 

assumptions. We regret the error. 
13

contribution of waste burning to the total mix is low). The modeling does contain some flawed 

assumptions, and only covers a relatively small portion of the state’s power sector. However, the fact that 

bioenergy-heavy Maine can achieve the emissions goals even while constraining new bioenergy development 

and counting full stack emissions from existing plants is a rebuttal to biomass industry arguments that new 

bioenergy buildout is necessary for achieving renewable energy goals. 

At the same time, the large percentage of biomass burners that is excluded from regulation (Figure 1) 

shows how little the existing industry has to fear from the GHG rule, at least in Maine. The biomass 

industry has always been careful to avoid the 250 MMBtu fossil-fuel limit, to avoid regulation as fossil-fueled 

plants under other EPA rules. These include the NSPS set for particulate matter emissions at fossil-fueled 

electric utility boilers, and the triggering provisions for Prevention of Significant Deterioration permitting 

(whereby if a boiler receives more than 250 MMBtu heat input from fossil fuels, it is regulated as a fossilfueled unit where PSD permitting is triggered by emissions of 100 tons of a criteria pollutant, rather than 

the 250 tons of emissions that trigger PSD permitting at biomass-fueled boilers).20 Similarly, most biomassburning plants are exempted from regulation under the GHG rule because they don’t receive more than 

250 MMBtu heat input from fossil fuels, or because they are commercial/industrial units that are not 

connected to the grid. Giving the existing biomass industry even less cause for concern about the rule, 

EPA’s modeling demonstrates that even biomass-heavy Maine can achieve its emissions reduction target 

while counting emissions from ongoing operation of existing biomass facilities.

Biomass availability is limited

Besides the decision to count stack emissions, there are a number of other factors that may inherently limit 

deployment of new bioenergy capacity in the modeling for the GHG rule, among them fuel availability. EPA 

based their initial estimates of renewable energy capacity on a “renewable energy potential” study by the 

National Renewable Energy Laboratory (NREL).21 Table 4, taken from that report, shows the technical 

potential for different forms of renewable energy, with technical potential meaning that almost all 

constraints are removed – for instance, under this analysis, a given area of land is considered “available” for 

all uses simultaneously. The estimate for biopower capacity is notably low, compared to other 

technologies, and even so, it’s probably a significant overestimate, because not only does NREL’s estimate 

include all forms of biopower (including methane collection from human and animal waste) but it considers 

that all biomass is available to generate combustion-biopower, rather than being collected for use as 

ethanol feedstock. Even with these assumptions, biopower is considered to have only 1.5% the generation 

potential of onshore wind (500 TWh versus 32,700 TWh). 

 

20 See http://www.pfpi.net/wp-content/uploads/2014/04/PFPI-Biomass-is-the-New-Coal-April-2-2014.pdf for a summary of 

some of the ways that biomass facilities are regulated differently from fossil-fueled boilers. 

21 Lopez, A. et al. U.S. renewable energy technical potentials: a GIS-based analysis. National Renewable Energy Laboratory 

Technical Report NREL/TP-6A20-51946. July, 2012. 
14

Table 4. NREL’s technical analysis for renewable energy capacity in the United States. 

Further, the NREL technical potential estimates are unrealistic for yet another reason – they are based on 

an NREL study of biomass availability in the United States that assumes that crop residues are a likely fuel,22

although these materials are notoriously problematic as fuel for combustion biopower. The study assessed 

potential biomass availability in each state, examining the categories of crop residues, forestry residues, 

“urban” wood, and mill residues. Crop residues make up the bulk of the biomass considered to be 

potentially available for biomass power generation in the study, outweighing forestry residues23 by a factor 

of 2.8 and urban wood by a factor of 5.1. This is why, in NREL’s assessment of technical potential for 

biomass power generation, the states of Ilinois, Indiana, Iowa, Missouri, Nebraska, and Ohio – not exactly 

known for their forestry resources – provide a combined total of 16 GW of the potential overall biopower 

capacity of 62 GW (26%).24 The problem with all this supposedly available crop-based biomass and the 

biopower capacity it potentially supports is that very few biomass plants or coal plants can actually burn 

crop residues for fuel, as is shown by the fact that almost every one of the biomass power plants currently 

being proposed and built around the country plans to burn wood as fuel.25 Crop residues are dirty and 

contain relatively high amounts of potassium and other elements that foul emissions controls. Collection, 

processing, and storage of these materials is expensive, a fact that EPA acknowledges in its IPM modeling by 

 

22 Milbrandt, A. A geographic perspective on the current biomass resource availability in the United States. National 

Renewable Energy Laboratory, Technical Report NREL/TP-560-39181. December, 2005. 

23 The category of “forest residues” in the Milbrandt report unequivocally includes whole tree harvesting. It 

includes “logging residues and other removals. Logging residues are the unused portions of trees cut, or 

killed by logging, and left in the woods. Other removals are considered trees cut or otherwise killed by 

cultural operations (e.g. pre-commercial thinning, weeding, etc.) or land clearings and forest uses that are 

not directly associated with round wood product harvests.” (Milbrandt, 2005, page 18).

24 Lopez, A. et al. U.S. renewable energy technical potentials: a GIS-based analysis. National Renewable Energy Laboratory 

Technical Report NREL/TP-6A20-51946. July, 2012. Data from Table 8, page 16. 

25 Forisk Wood Energy US database, May 6, 2014. 
15

attaching not only a $12/dry ton surcharge on all types of biomass for transport, but also a $20/ton 

surcharge for storage of crop residue-derived biomass fuels, since they can only be collected at certain 

times of the year and must be stored in quantity until they are needed.26 

Even if treated as carbon neutral, bioenergy is a costly way to “reduce” CO2 emissions

In addition to biomass fuel costs, which are perpetual (in contrast to the “fuels” of wind and solar energy, 

which are perpetually free) biomass power plants are expensive to build and require substantial and 

ongoing infrastructure investments. EPA’s IPM documentation document contains the data reproduced in 

Table 5,

27 which shows the costs of building new infrastructure. Bioenergy is substantially more expensive 

than onshore wind, per kilowatt-year, including both the initial infrastructure investment and ongoing 

“fixed” costs (the annual expense of maintaining a unit) and “variable” costs (expenses associated with 

operating units, including for pollution controls). 

Table 5. EPA’s IPM model assumptions for the costs of building new renewable energy infrastructure. 

Biomass energy costs substantially exceed those of onshore wind. 

As explained above, biomass co-firing is also costly. EPA provides a detailed treatment of the costs and 

logistics of biomass co-firing at coal plants, finding that even if biogenic CO2 emissions are treated as zero, 

the “reductions” in fossil fuel CO2 emissions at coal plants co-firing 10% biomass ranges from $30 - $80 per 

ton of CO2, concluding

“Replacing some coal with low levels of biomass co-firing may result in stack CO2 increases. Even if biogenic CO2

emissions are not counted as part of stack emissions, biomass co-firing is a relatively costly 

approach to CO2 reductions at existing coal steam boilers when compared to other measures such 

as heat rate improvements and re-dispatch of generation supply to other existing capacity with lower CO2 emissions 

rates.”28

Combined, fuel costs, infrastructure costs, and maintenance costs can quickly drive bioenergy costs to an 

uneconomic level where the IPM model is likely to “choose” lower cost renewable energy options over 

bioenergy. 

 

26 U.S. Environmental Protection Agency. Documentation for EPA Base Case v.5.13 Using the Integrated Planning Model. 

Page 11-2.

27 Ibid, page 4-32.

28 U.S. Environmental Protection Agency. Technical Support Document for Carbon Pollution Guidelines for Existing Power 

Plants. GHG Abatement Masures, page 6-16. 
16

EPA isn’t giving up on bioenergy

While the IPM modeling does not project development of new biomass capacity, EPA suggests that the 

biomass energy industry can still be developed by the states as they seek to meet emissions reduction goals

- (emphasis added) –

“EPA notes that RE target generation levels are used solely to inform each state’s goal calculation and are not 

prescriptive of any RE compliance outcome – either in sum or by technology type. Consequently, whether or not any 

particular RE technology is considered in this Alternative RE Approach does not have any bearing on what 

types of RE generation a state may consider in developing its state plan for complying with its state 

goal”

29

A footnote to this section additionally emphasizes, 

“Existing dedicated biomass and landfill gas facilities contribute to RE target generation levels. The analysis in this 

TSD does not consider biomass renewables in its evaluation of renewable development potential for BSER, but the 

preamble discusses the possibility of a path for states to consider it in their plans.”

Thus, while EPA’s own modeling does not plan for development in the bioenergy power sector, the rule 

leaves the door open for states to continue developing biomass power. But how will states account for 

emissions? 

Future regulation of biogenic CO2 emissions

However, EPA has indicated both in the NSPS and the ESPS rules that the Agency recognizes the 

importance of devising a carbon accounting framework for bioenergy that will properly account for lifecycle 

greenhouse gas emissions from burning biomass, especially wood. In the meantime, indications are that 

EPA supports the concept that burning waste wood and forestry residues has a lower lifecycle greenhouse 

gas impact than burning trees that are harvested for fuel. This direction is indicated in the Region 9 EPA

response to comments on the recently issued PSD permit for the Sierra Pacific Anderson biomass facility in 

California. The document, issued in April 2014, states that EPA is still working on an accounting framework 

for bioenergy: 

“As previously stated, EPA is not currently prepared to classify any particular biomass feedstocks as a “clean fuel” or 

“inherently lower emitting” or to engage in a quantitative ranking and comparison of the net atmospheric 

contribution of such fuels”

30

but then goes on to say that fuels will be restricted at the plant to those with lower net emissions impacts

(emphasis added):

“The revision is intended to clarify that SPI will be limited to the following types of biomass fuels: mill residues; 

untreated wood debris from urban areas (e.g., pallets and crates); agricultural crops and residues; forest residues; 

 

29 U.S. Environmental Protection Agency. Alternative Renewable Energy Approach Technical Support Document. Technical 

Support Document (TSD) for Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units. Docket ID No. EPA-HQ-OAR-2013-0602, June 2014.

30 U.S. Environmental Protection Agency, Region 9. Responses to Public Comments on the Proposed 

Prevention of Significant Deterioration Permit Major Modification for Sierra Pacific Industries - Anderson 

Division. April, 2014. Page 10 (http://www.epa.gov/region9/air/permit/pdf/spi-anderson/spi-anderson-finalpermit-public-comment-response-2014-04-25.pdf)
17

and non-merchantable forest biomass. EPA believes that these revisions to Permit Condition X.G. will limit the 

facility to the types of biomass fuels that are generally considered to have lower net atmospheric 

contributions when combusted. In addition, the record reflects that SPI’s proposed cogeneration project is not 

intended to use timber harvested solely for the purpose of biomass combustion. See Second Recirculated Draft EIR, 

February 2012, at 2.0-20. Nevertheless, in response to the commenter’s concerns, EPA’s revisions to Permit 

Condition X.G. are intended to preclude the use of this type of feedstock.”

31

This statement suggests that EPA’s thinking on the topic of bioenergy emissions is evolving in the direction 

laid out by the most current science, which recognizes that burning trees in power plants is highly 

counterproductive if the goal is to reduce energy sector greenhouse gas emissions. However, it is 

important to note that the permit for SPI Anderson issued by Region IX does not actually prohibit use of 

trees as biomass fuel. The permitted fuels include:32

a. Untreated wood pallets, crates, dunnage, untreated manufacturing and construction wood debris from urban 

areas;

b. All agricultural crops or residues;

c. Mill residues including hog fuel, shavings, sawdust, trimmings, and bark.

d. Forest residues including treetops, non-merchantable sections of the stem,

branches, and bark, left on the ground after logging or accumulating as a result of

a storm, fire, delimbing, or other similar disturbance.

e. Non-merchantable forest biomass consisting of byproducts and residuals of forest

management activities identified to follow all of the following practices;

(1)Harvested pursuant to an approved timber management plan prepared in

accordance with the Zberg-Nejedly Forest practice Act of 1973 or other

locally or nationally approved plan; and

(2) Harvested for the purpose of forest fire fuel reduction or forest stand

improvement.

Even if EPA had written a permit that actually restricted the facility to use of true “waste” wood, matters of 

practical implementation would still remain. Existing and proposed biomass plants currently do not just 

burn waste wood and “residues,”

33 and there is a real danger that if wood waste is treated as having zero 

or negligible emissions, then everything will be defined as “waste.” For instance, Dominion Energy in Virginia 

is converting three coal-fired power plants to burn wood, with total forest wood consumption around 2 

million tons of forest wood per year (translating to just over 2 million tons of CO2 emitted per year). A

letter from Dominion to EPA’s Science Advisory Board on biogenic carbon states that waste wood “to us 

means forest materials including residues (tree tops, non-merchantable sections of stem, branches, and bark), small 

trees and other low value materials”

34 (emphasis added). Covanta Energy, another operator of wood-fired 

biomass power plants (as well as municipal waste incinerators) distinguishes residues from whole tree chips 

but nonetheless treats whole tree chips as waste wood, stating that their Burney Mountain Power facility in 

 

31 Ibid, page 11

32 U.S. Environmental Protection Agency, Region IX. PSD permit for Sierra Pacific Industries, Anderson. PSD permit 

number SAC 12-01. April 25, 2014. 

33 Forest wood use for biomass fuel is growing so fast, and in so many categories, that the bioenergy tracking service Forisk 

has recently partitioned energy wood use into categories of “softwood pulpwood,”, “hardwood pulpwood,” “logging 

resdues/dirty chips,” “urban wood,” and “mill residues.” Forisk Wood Energy US database, May 6, 2014. 

34 Pamela F. Faggert, Dominion Resources Services, Inc. Comments to the Science Advisory Board biogenic carbon emissions 

panel on its draft advisory report regarding EPA’s accounting framework for biogenic CO2 emissions from stationary 

sources. March 16, 2012.
18

California burns “waste” comprised of “forest residue, mill residue and whole tree chips.”35 Their 

website additionally states that they use “logs from forest thinning” for fuel.36 

Further, even if a facility does truly only burn forestry residues generated during sawlog harvesting, 

modeling shows that net CO2 emissions from residues can still be significant (the SAB report states that 

burning “residues” and waste wood can have a significant carbon impact;

37 for an explanation of why this is 

the case, see Appendix 2). The EPA has still not stated what timeframe is relevant for biogenic carbon 

accounting and what timeframe is important for reducing net emissions from the power sector. If it is 

anything less than one to two decades, forestry residues do not qualify as a “low carbon” fuel. 

Could the GHG rule increase forest harvesting for biomass energy? 

As demonstrated above, EPA has left the door open for states to propose bioenergy as a means to increase 

renewable energy capacity. The Agency is soliciting comment on deployment of bioenergy at the state 

level:

“Beyond the types of state plan measures already discussed in this section of the preamble, the agency has identified 

a number of other measures that could also lead to CO2 emission reductions from EGUs. These include, for 

example, electricity transmission and distribution efficiency improvements, retrofitting affected EGUs with partial 

CCS, the use of biomass-derived fuels at affected EGUs, and use of new NGCC units. Although the emission 

reduction methods discussed in this section are not proposed to be part of BSER, the agency anticipates that some 

states may be interested using these approaches in their state plans. The agency solicits comment on whether 

these measures are appropriate to include in a state plan to achieve CO2 emission reductions from 

affected EGUs.”

38 (emphasis added)

Given that the EPA itself is supposed to be coming up with a framework for carbon accounting, and given 

that EPA solicited, and received, abundant comments on greenhouse gas emissions from bioenergy when it 

issued the biogenic C deferral, to say nothing of the extensive input during the US Court of Appeals case 

on the deferral and the expert input provided by the Science Advisory Board, for EPA to be soliciting 

additional comment on whether burning biomass can “reduce” greenhouse gas emissions seems somewhat 

superfluous. The Agency should have more than enough information now to produce a science-based 

carbon accounting framework. 

Further, the lack of enforceable language in the GHG rule suggests that even if EPA does develop a carbon 

accounting framework for bioenergy, it could be difficult to get states to use it. The ESPS suggests it’s likely 

that the states will deploy bioenergy:

“Because of the positive attributes of certain biomass-derived fuels, the EPA also recognizes that biomass-derived 

fuels can play an important role in CO2 emission reduction strategies. We anticipate that states likely will consider 

biomass-derived fuels in energy production as a way to mitigate the CO2 emissions attributed to the energy sector 

 

35 Other Renewable Energy Projects, Covanta website, (http://www.covantaenergy.com/what-we-do/our-services/otherrenewable-energy.aspx).

36 http://www.covantaenergy.com/what-we-do/our-services/other-renewable-energy.aspx

37 The report states, “For logging residues and other feedstocks that decay over longer periods, decomposition cannot be 

assumed to be instantaneous... For residues, consider alternate fates (e.g., some forest residues may be burned if not used 

for bioenergy) and information about decay. An appropriate analysis using decay functions would yield information on the 

storage of ecosystem carbon in forest residues.”

38 Environmental Protection Agency. 40 CFR Part 60: Carbon pollution emission guidelines for existing stationary sources: 

electric generating units; proposed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 34923
19

and include them as part of their plans to meet the emission reduction requirements of this rule and we think it is 

important to define a clear path for states to do so.”

39

If EPA came out with a strong and decisive carbon accounting framework that acknowledged the true 

emissions from burning different types of biomass, but especially wood, states that were serious about 

reducing emissions would likely eliminate large-scale bioenergy from their list of options, as Massachusetts 

has done and as Vermont is starting to do.40 However, there is little indication in the rule that EPA has a

means of enforcing a science-based carbon accounting framework at the state level. Indeed, the language 

around deployment of the carbon accounting framework is notably weak: 

“The EPA expects that the framework, when finalized, will be a resource that could help inform states in the 

development of their CAA section 111(d) plans.”

41 (emphasis added)

Unfortunately, some of the states that are now experiencing the highest bioenergy development are also 

those states that are targeted by the rule to show the greatest reductions in power sector emissions rates. 

Ranked in descending order of the percent reduction required, Washington, South Carolina, Oregon, New 

Hampshire, and Georgia are all states that have entertained proposals or actually built large, low-efficiency, 

wood-burning power plants (see Appendix 1 for full list of states, EPA’s current emission rate estimates, 

and target emission rates). These states, and the bioenergy developers therein, will no doubt pressure EPA 

to allow bioenergy as a means of “mitigating” power sector carbon emissions. Unless there is strong 

implementation of a carbon accounting framework, and rigorous oversight to ensure that only fuels with 

very low lifecycle greenhouse gas emissions are burned (thereby severely limiting development of the 

biomass industry) there is a real possibility that the GHG rule could actually increase forest harvesting for 

bioenergy, and commensurately, greenhouse gas emissions. This is especially true if states displace actual 

no-emissions renewable energy that would be built with biomass power. Meanwhile, the treatment of 

bioenergy as having zero carbon emissions in the GHG rule goal rate equation continues to promote the 

erroneous concept that burning biomass has no greenhouse gas impacts. 

Is “beyond the fenceline” carbon offsetting for bioenergy allowable under the GHG rule? 

Certain to become an issue of contention in the proposed greenhouse gas rule is the extensive use of 

“beyond the fenceline” mitigation measures for reducing greenhouse gas emissions, as EPA has recognized 

in its request for comments.42 While the NSPS rule treats an individual power plant as the entity of 

concern, setting a fixed emissions standard that applies at the facility, the ESPS seeks a “best system of 

emission reduction” (BSER) for entities where the boundaries are less clear. Does increased use of low- or 

zero-emissions renewable energy (EPA’s terms) somewhere in a state constitute a “reduction” in 

greenhouse gas emissions from that state’s coal-fired plants? Can increased demand-side efficiency likewise 

constitute a reduction? These questions will no doubt be extensively argued and likely litigated as well. 

Meanwhile, it is important to recognize that most claims for bioenergy as having “low” or “zero” carbon 

emissions also rely on “beyond the fenceline” mitigation. Biomass can’t play a role in reducing greenhouse 

gas emissions at the time it is burned, because essentially all biomass fuels emit more CO2 per unit energy 

generated than all fossil fuels. Thus, any claim that bioenergy emits less CO2 than fossil fuels relies on 

 

39 Ibid, page 34924

40 See http://www.pfpi.net/vermont-biomass-power-plant-denied-approval-on-basis-of-greenhouse-gas-emissions

41 Ibid, page 34927

42 Environmental Protection Agency. 40 CFR Part 60: Carbon pollution emission guidelines for existing stationary sources: 

electric generating units; proposed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 34888
20

calculation of net CO2 emissions over time. Lifecycle GHG accounting can show lower net emissions for 

biomass than for fossil fuels, based on either the idea that fuels are waste that would decompose and 

inevitably emit CO2 anyway, or that fuels are sourced from forests or crops that can regow and sequester 

an equivalent amount of CO2 as emitted by burning. However, as neither process is instantaneous, no 

biomass energy can be instantaneously carbon neutral. 

In fact, both justifications for eventual carbon neutrality of biomass energy are essentially carbon offset 

schemes, in that they assume that a process occurring in some other place, and at some future time, 

compensates for CO2 emissions from burning biomass now (see Appendix 2 for modeling of typical time 

periods required for bioenergy CO2 emissions to be offset). Can the GHG rule accommodate a scenario

whereby it is acceptable to increase powerplant or grid-wide emissions by substituting biomass for fossil 

fuels, based on the idea that emissions will eventually be offset? Does EPA have the jurisdiction under the 

GHG rule to discriminate between stack emissions at the present time – which for every biomass fuel are 

greater than emissions from coal, per megawatt-hour – and “net” emissions in the future, which are 

calculated assuming that emissions are offset? 

In a narrower context, but also pertaining to Clean Air Act implementation, the US Court of Appeals has 

already weighed in on the question of whether offsetting of bioenergy greenhouse gas emissions constitutes 

a reduction. Much of the court’s reasoning for ruling against EPA’s deferral of biogenic CO2 regulation 

turned on the plain meaning of the word “emit,” and the fact that the Clean Air Act regulates stack 

emissions of power plants and other stationary sources. However, a concurrent opinion issued with the 

main ruling also explained that the Clean Air Act forecloses any “offsetting” approach – i.e., taking off-site 

carbon sequestration into account as a compensating factor that can mitigate a power plant’s emissions –

because “The statute does not allow EPA to exempt those sources’ emissions of a covered air pollutant just because 

the effects of those sources’ emissions on the atmosphere might be offset in some other way.”43

The EPA may have already internalized this lesson with regard to the ability of states to use actual carbon 

offsets as a means of mitigating power sector emissions under the GHG rule, whereby, for instance, a 

forest and its carbon sequestration capacity is preserved to compensate for a fossil fuel plant’s CO2

emissions. The ESPS rule is initially somewhat ambiguous as to whether the GHG rule allows offsets, but, 

an assessment included in a technical support document seems to clearly prohibit use of offsets for 

mitigation:

“For emission budget trading programs that regulate EGUs and include offsets, which we define here as emissions 

reductions from sources not regulated by the trading program, emissions reductions from offsets would not 

be counted when evaluating CO2 emission performance of affected EGUs, because those reductions would not 

come from those affected EGUs”

44

The prohibition on use of offsets may provide some guidance for the parallel issue of bioenergy emissions 

offsetting. If EPA does not intend to allow actual offsets under the rule, then it is hard to see how biomass 

emissions that rely on offsite regrowth of fuels can be allowable, especially when most power plant 

operators do not own or otherwise control the forest lands where future carbon sequestration is 

ostensibly to occur.

 

43 Center for Biological Diversity v. EPA, D.C. Cir. No. 11-1101, July 12, 2013; Concurrence page 3.

44 U.S. EPA. Projecting EGU CO2 Emission Performance in State Plans. Technical Support Document (TSD) for Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units. Docket ID No. EPA-HQOAR-2013-0602, June 2014. Page 37.
21

The situation with regard to “waste” materials that would decompose anyway may be more ambiguous. 

The offsetting of emissions from burning true wastes simply relies on time, and the assumption that 

decomposition would be emitting greenhouse gases anyway if the material were not burned for fuel. In this 

case, as decomposition can take years to decades, and net emissions from biomass burning will almost 

always exceed “anyway” emissions from decomposition over multiple years (see Appendix 2), the question 

is simply whether the ESPS rule can count hypothetical reductions in emissions that will occur at some 

future time as a real reduction in emissions now. 
22

Appendix 1: EPA’s current and target emissions rates for states ranked by emission reduction 

required under the GHG rule45

 

45 U.S Environmental Protection Agency. Goal Computation Technical Support Document for the CAA Section 111(d) 

Emission Guidelines for Existing Power Plants Docket ID No. EPA-HQ-OAR-2013-0602. June, 2014. 

current fossil rate fossil + nukes + RE block 1 block 1&2 1&2&3 1&2&3&4 % reduction

Washington 1,379 756 728 444 298 215 72%

Arizona 1,551 1,453 1,394 843 814 702 52%

South Carolina 1,791 1,587 1,506 1,342 866 772 51%

Oregon 1,081 717 701 565 452 372 48%

New Hampshire 1,119 905 887 710 532 486 46%

Georgia 1,598 1,500 1,433 1,216 926 834 44%

Arkansas 1,722 1,634 1,554 1,058 996 910 44%

New York 1,096 978 970 828 652 549 44%

New Jersey 1,035 928 916 811 616 531 43%

Minnesota 2,013 1,470 1,389 999 1,042 873 41%

North Carolina 1,772 1,647 1,560 1,248 1,125 992 40%

Louisiana 1,533 1,455 1,404 1,043 978 883 39%

Tennessee 2,015 1,903 1,797 1,698 1,322 1,163 39%

Texas 1,420 1,284 1,235 979 861 791 38%

Florida 1,238 1,199 1,169 882 812 740 38%

Virginia 1,438 1,302 1,258 1,047 894 810 38%

Massachusetts 1,001 925 915 819 661 576 38%

Mississippi 1,140 1,093 1,071 809 752 692 37%

Maryland 2,029 1,870 1,772 1,722 1,394 1,187 37%

Oklahoma 1,562 1,387 1,334 1,053 964 895 35%

Colorado 1,959 1,714 1,621 1,334 1,222 1,108 35%

South Dakota 2,256 1,135 1,067 732 900 741 35%

Nevada 1,091 988 970 799 720 647 35%

Wisconsin 1,988 1,827 1,728 1,487 1,379 1,203 34%

New Mexico 1,798 1,586 1,513 1,277 1,163 1,048 34%

Illinois 2,189 1,894 1,784 1,614 1,476 1,271 33%

Idaho 858 339 339 339 291 228 33%

Delaware 1,255 1,234 1,211 996 892 841 32%

Michigan 1,814 1,690 1,603 1,408 1,339 1,161 31%

Pennsylvania 1,627 1,531 1,458 1,393 1,157 1,052 31%

Connecticut 844 765 764 733 643 540 29%

Ohio 1,897 1,850 1,751 1,673 1,512 1,338 28%

Utah 1,874 1,813 1,713 1,508 1,454 1,322 27%

Alabama 1,518 1,444 1,385 1,264 1,139 1,059 27%

Nebraska 2,162 2,009 1,889 1,803 1,652 1,479 26%

Alaska 1,368 1,351 1,340 1,237 1,191 1,003 26%

California 900 698 697 662 615 537 23%

Kansas 2,320 1,940 1,828 1,828 1,658 1,499 23%

Missouri 2,010 1,963 1,849 1,742 1,711 1,544 21%

Montana 2,439 2,246 2,114 2,114 1,936 1,771 21%

Indiana 1,991 1,924 1,817 1,772 1,707 1,531 20%

West Virginia 2,056 2,019 1,898 1,898 1,687 1,620 20%

Wyoming 2,331 2,115 1,988 1,957 1,771 1,714 19%

Kentucky 2,166 2,158 2,028 1,978 1,947 1,763 18%

Iowa 2,197 1,552 1,461 1,304 1,472 1,301 16%

Hawaii 1,783 1,540 1,512 1,512 1,485 1,306 15%

Rhode Island 918 907 907 907 867 782 14%

Maine 873 437 437 425 451 378 14%

North Dakota 2,368 1,994 1,875 1,875 1,865 1,783 11%
23

Appendix 2: Technical information on CO2 from biomass energy 

Carbon dioxide emissions from power plants

All fuels produce CO2 when burned. The general assumption is that all carbon in the fuel is converted to 

CO2, though in fact, some small fraction is emitted as carbon monoxide (CO) and other carbon-containing 

compounds such as volatile organics. 

CO2 emissions from power plants are typically expressed in units of pounds of CO2 per megawatt-hour of 

electricity produced (lb CO2/MWh). 

How much CO2 does burning wood emit? 

Biomass power plants may burn a variety of fuels, including energy crops, crop residues, wood, and “woodderived fuels,” the residuals from pulp and papermaking.46 However, the overwhelming majority of new 

biomass power plants now being proposed burn wood. The rest of this factsheet assumes that wood is the 

main fuel burned for biomass. 

Green wood when it is harvested can be more than 50% water by weight. A typical industry assumption is 

that wood is 45% water by weight. Of the 55% “bone dry” mass that is left after subtracting water weight, 

around 50% is carbon.47 The conversion factor for carbon to CO2 during combustion is the molecular 

weight of CO2 (44) divided by the molecular weight of carbon (12). 

The full conversion equation thus reveals that burning one ton of “green” wood at 45% moisture content 

emits just over one ton of CO2:

1 ton green wood * 0.55 ton bone dry wood/ton green wood * 0.5 ton carbon/ton bone dry wood *44 

tons CO2÷12 tons carbon = 1.008 tons CO2

How much CO2 does a biomass power plant emit? 

To compare the amount of CO2 emitted by biomass power plants versus a same-sized coal or gas plant, the 

CO2 emissions need to be expressed using a common currency, rather than in terms of the pounds or tons 

of fuel burned. 

The CO2 per megawatt-hour produced at any power plant is a function of two main factors:

 The amount of CO2 emitted by the fuel when it is burned, relative to its energy content, or “heat 

content” in million Btu (lb CO2/MMBtu)

 Facility efficiency (MMBtu output of useful energy divided by MMBtu of fuel input). The lower the 

efficiency of the facility, the more fuel that has to be burned to produce a given amount of “useful” 

energy.

 

46 These wastes are high in moisture content and therefore low in energy, but they are an important fuel for the industries 

where they are generated, and use of them as fuel solves the industry’s disposal problems. 

47 The assumption of 50% carbon content is an oversimplification, as species vary in carbon content 

(http://www.sciencedirect.com/science/article/pii/S0961953403000333; also 

http://is.muni.cz/el/1423/podzim2013/MEB423/um/Wood_Combustion_Lesson_02.pdf) but it is a representative average 

that is widely used. See for instance http://www.epa.gov/burnwise/workshop2011/WoodCombustion-Curkeet.pdf
24

Coal heat content ranges from 10,000 to over 12,000 Btu per pound,48 depending on its composition. 

Biomass heat content depends on moisture content and composition. “Bone dry” wood with zero 

moisture has an average heat content of about 8,600 Btu per pound.49 Green wood “as delivered” at a 

typical moisture content of 45% has a heat content50 of about 4,730 Btu/lb. 

Expressing CO2 emission relative to the heating value of a fuel (in MMBtu) provides a “common currency” 

that takes moisture content and fuel mass out of the equation when comparing fuels. Although a ton of 

coal contains a great deal more inherent energy than a ton of wood, biomass and coal emit similar amounts 

of CO2 per MMBtu of energy in the fuel.51 If biomass facilities were as efficient as coal plants, then samesized facilities would emit similar amounts ofCO2. However, a biomass plant is actually much less efficient 

than a coal plant,52 in great part because it takes energy to evaporate moisture in biomass before “useful 

energy” can be produced from fuel combustion.53

The following table summarizes this information for natural gas, coal, and biomass facilities. 

Table 1: CO2 emissions at the stack for biomass, coal, and natural gas electricity generation54

Table 1. Per megawatt-hour, CO2 stack emissions at the biomass plant are about 145% those of coal 

plant,55 and 250% - 340% those of a gas plant (depending on whether it is a single cycle plant, or employs a 

combustion turbine). 

Effect of biomass co-firing on coal plant CO2 emissions

Just as a biomass plant emits more CO2 per MWh than a coal plant, co-firing biomass in a coal plant 

decreases overall facility efficiency56 and increases CO2 stack emissions. The more biomass that is co-fired, 

 

48 Values converted from EIA data which is given in units of million btu per short ton: 

http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb1205

49 Biomass Energy Data Book 4th Edition, page 205: http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

50 This is the “higher heating value.” See page 201 of Biomass Energy Data Book 4th Edition: 

http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

51 Both emit a great deal more CO2 per unit energy in the fuel than natural gas.

52 Typical assumed peak efficiency for biomass electricity plants is around 24%. However, many facilities have considerably 

lower efficiencies of 19% – 20%. In general, the smaller a plant is, the less efficient it tends to be. 

53 Biomass Energy Data Book 4th Edition, page 205: http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

54 Sources for table: Average heat content of coal: http://www.eia.gov/coal/production/quarterly/co2_article/co2.html

Heat content of biomass: Biomass Energy Data Book 4th Edition, page 204: http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

CO2 emissions for natural gas: http://www.eia.gov/environment/emissions/co2_vol_mass.cfm

55 The 33% efficiency value used as representative of coal plant efficiency is the average efficiency of the existing US fleet of 

coal plants. The newest coal plants are more efficient. 

56 See Electric Power Research Institute report on co-firing at 

http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000000001004319

Technology

Fuel CO2 emissions 

(lb/MMBtu heat input)

Facility 

efficiency

MMBtu required to 

produce one MWh

Lb CO2 emitted 

per MWh

Gas combined cycle 117.1 45% 7.54 883

Gas steam turbine 117.1 33% 10.40 1,218

Coal steam turbine 206 34% 10.15 2,086

Biomass steam turbine 213 24% 14.22 3,029
25

the further the facility’s efficiency will move down the scale from the value for a 100% coal-fired plant 

(~33% on average in the US) towards the value for a 100% biomass-fired plant (~24%). Typical co-firing 

rates of ~10% biomass have been observed to degrade coal plant efficiency by 1% - 2%. 

Treatment of biomass power as “carbon neutral” 

Despite the fact that biomass power plants emit more CO2 than fossil fueled plants per megawatt-hour, 

biomass power has been treated as carbon neutral based on two main arguments: 

 The first is that mostly waste materials - such as lumber mill shavings, paper mill waste, and 

“forestry residues,” the tops and limbs left over after saw-timber harvesting - are used as fuel. 

Because such materials would inevitably decompose and emit CO2, it is argued that burning them as 

fuel does not emit more CO2 than would occur in any case. The problem with this argument is 

that while burning emits CO2 instantaneously, wood decomposition takes years to decades.

 The second argument for bioenergy being carbon neutral states that when whole trees are used as 

fuel, carbon emissions are “offset” as standing and/or new trees grow and take up an equivalent 

amount of CO2 as was released by burning. The problem with this argument is that burning 

biomass emits carbon instantly, while regrowth takes decades, and in addition, harvesting forests for 

fuel compromises their ability to serve as an ongoing carbon sink for fossil fuel emissions. 

These arguments are addressed in more detail below. 

The “Biomass is carbon neutral because it would decompose anyway” argument

Assuming biomass combustion emissions to be zero because the CO2 would have been emitted “anyway” 

from decomposition ignores the fact, highly relevant to calculating the impact of CO2 emissions on 

atmospheric CO2 levels and climate warming, that burning biomass emits CO2 instantly, while letting it 

decompose emits it slowly. Figures 1 and 2 show results from a model57 of CO2 emissions from alternate 

fates of biomass – either being burned at a 50 MW biopower plant, or left to decompose. The model 

assumes a moderate decomposition rate representative of Northeastern forests, and reveals that over 

time, emissions from burning will always exceed those from decomposition (Figure1). For instance, after 

ten years of operation, a 50 MW facility would have emitted about 6.3 million tons of CO2, whereas if 

those fuels had been left unburned, CO2 emissions would have been about 2.3 million tons, a difference of 

4 million tons (represented by the black arrow). 

 

57 The model assumes:

Green wood is 45% water by weight

Bone dry wood is 50% carbon 

% wood left at year x = e-0.09*(year-x – 0.05)

Wood decomposed at year x = (1 - % wood left at year x)

Facility efficiencies: Coal: 33%; Biomass: 24%; Natural Gas: 45%
26

Figure 1: Comparison of CO2 emissions from biomass combustion versus biomass decomposition 

over time.

Figure 1. After ten years of facility operation, burning residues will have emitted about four million tons 

more CO2 than under the scenario where they are allowed to decompose. 

Figure 2 shows that same four million tons as the “net” or “additional” CO2 that is emitted by burning 

biomass rather than letting it decompose, and shows that this is approximately equal to the CO2 that 

would be emitted by a 50 MW coal plant over ten years of facility operation. Thereafter, in this example, a 

biomass plant may begin to show lower net emissions than a coal plant – provided that the fuel is truly 

“waste wood that would have decomposed anyway,” and not trees harvested for bioenergy, which but for 

being harvested would have continued to grow and sequester carbon (discussed below). 

Figure 2 shows that for this example, net emissions from the biomass plant fueled exclusively by waste 

wood exceed those from a same-sized natural gas plant for more than 30 years. 
27

Figure 2: Net emissions from bioenergy exceed fossil fuel emissions even when burning waste 

wood

Figure 2. Even after subtracting “anyway” emissions from decomposition, net CO2 emissions from a 

biomass plant exceed those from a coal plant for about ten years, and exceed those from a gas plant for 

more than 30 years. 

These results mean that instead of reducing emissions from power generation, biomass power plants 

burning waste wood “that would decompose anyway” actually increase emissions for at least a decade, 

even compared to inefficient coal plants. 

The “Biomass is carbon neutral because forests take up CO2” argument

Forests (along with beneficial agricultural activities) are the only carbon sink reported in EPA’s inventory of 

greenhouse gas emissions and sinks, and are estimated to sequester about 13.5% of US CO2 emissions per 

year.58 Forestry activities that cut trees and disturb soils are recognized as sources of CO2. Critically, 

forests take up CO2 emitted by all sectors, including the fossil fueled electricity generation sector. 

Net carbon emissions from burning wood as fuel can theoretically be offset by trees re-growing and taking 

up an equivalent amount of CO2 as was released by burning. However, numerous scientific studies59

demonstrate that carbon emissions of biomass power plants are not offset by new forest growth for 

decades, and that meanwhile, forest carbon uptake is decreased by the very harvesting required to fuel 

biomass power plants. 

 

58 U.S. EPA 40 CFT Parts 60, 70, 71 et al. Standards of Performance for Greenhouse Gas Emissions From New Stationary 

Sources: Electric Generating Units; Proposed Rule (page 1441)

59 See for example Searchinger, T., et al. 2009. Fixing a critical climate accounting error. Science 326: 527-528 ; Colnes, A., et al.

2012. Biomass supply and carbon accounting for Southeastern Forests. Biomass Energy Resource Center, Montpelier, VT; 

Mitchell, S., et al. 2012. Carbon debt and carbon sequestration parity in forest bioenergy production. GCB Bioenergy (2012) 

doi:10.1111/j.1757-1707.2012.01173.x; McKechnie, J. et al. 2011. Forest bioenergy or forest carbon? Assessing trade-offs in 

greenhouse gas mitigation with wood-based fuels. Environmental Science and Technology, 45: 789-795.
28

Because biomass power plants emit more CO2 per megawatt-hour than fossil-fueled plants, the atmosphere 

“sees” more power sector CO2 under a biomass power scenario (that harvests forests and replaces them 

with seedlings) than it does under a fossil fuel power scenario (where middle-aged and mature forests are 

allowed to continue growing and sequestering carbon). 

Figure 3 is a generalized schematic showing that it takes time for net uptake of CO2 from new forest 

growth to bend the net emissions curve for biomass downward. Because biomass plants emit more CO2 

than fossil fueled plants per megawatt-hour, until that point when the bioenergy curve crosses the 

emissions line for fossil fuels, the atmosphere is seeing more CO2 from a biomass plant than from an 

equivalently sized fossil fueled plant. For biomass facilities that are harvesting new whole trees as fuel, 

forest modeling demonstrates that it takes 35 to more than 90 years for new forest growth to offset the 

extra CO2 emissions from burning biomass rather than fossil fuels, with shorter offsetting times for 

biomass-coal comparisons, and longer times for biomass-natural gas comparisons. 60

Figure 3: Net bioenergy emissions significantly exceed fossil fuel emissions for decades when 

carbon-sequestering trees are harvested for fuel

Figure 3. Generalized schematic of CO2 emissions from a biomass power plant v. a fossil fuel plant.61 Net 

emissions for the biomass plant assume that trees are allowed to fully regrow before the next harvest, a 

condition necessary for emissions from biomass burning to be neutralized.

 

60 Walker, T., et al. 2012. Carbon accounting for woody biomass from Massachusetts (USA) managed forests: a framework 

for determining the temporal impacts of wood biomass energy on atmospheric greenhouse gas levels. Journal of Sustainable 

Forestry, 32:1-2, 130 – 158; 2010; Searchinger, T., et al. 2009. Fixing a critical climate accounting error. Science 326: 527-

528; Colnes, A., et al. 2012. Biomass supply and carbon accounting for Southeastern Forests. Biomass Energy Resource 

Center, Montpelier, VT; Mitchell, S., et al. 2012. Carbon debt and carbon sequestration parity in forest bioenergy

production. GCB Bioenergy (2012) doi:10.1111/j.1757-1707.2012.01173.x.

61 Figure after Walker, T., et al. 2012. Carbon accounting for woody biomass from Massachusetts (USA) managed forests: a 

framework for determining the temporal impacts of wood biomass energy on atmospheric greenhouse gas levels. Journal of 

Sustainable Forestry, 32:1-2, 130 – 158.