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 CO 2 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 scien ce

- based

................................ ......................... 4

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

......................... 5

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

........................ 8

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

................................ ................................ .............. 9

E PA’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, bio energy is a costly way to “reduce” CO 2 emissions

............................ 15

EPA isn’t giving up on bioenergy

................................ ................................ ................................ ................................ ... 16

Future regulation of biogenic CO 2 emission s

................................ ................................ ................................ ......... 16

Could the GHG rule increase forest harvesting for biomass energy?

................................ ................................ ... 18

Is “beyond the fenceline” carbon offsetting for bioenerg y 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 CO 2 from biomass energy

................................ ................................ ......... 23

Carbon dioxide emissions from power plants

................................ ................................ ................................ ....... 23

How much CO 2 does burning wood emit?

................................ ................................ ................................ ............ 23

How much CO 2 does a biomass power plant emit?

................................ ................................ ............................. 23

Effect of biomass co

- firing on c oal plant CO 2 emissions

................................ ................................ ...................... 24

Treatment of biomass power as “carbon neutral”

................................ ................................ ................................ 25

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

................................ ........ 25

The “Biomass is carbon neutral because forests take up CO 2 ” argument

................................ ....................... 272

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 Em issions 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 state s to achieve their 2020 and 2030 target emissions rate s ( expressed as pounds of

CO 2 per megawat t

- 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 e missions of CO 2 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 rate s.

B iomass 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 CO 2 t han coal plants, and that co

- firing biomass at coal plants increases CO 2 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 existi ng

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 CO 2 emissions
The short answer is that despite all the time and energy t hat EPA a nd others have devoted to developing a biogenic carbon accounting framework, EPA’s estimates of current power sector emissions, the 2012
baseline, treat s standalone biomass power plants as having zero carbon emissions , although emissions from

biomass co

- fi red 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 CO 2 emissions are summed in the numerator, and power generation (as MWh) is sum med in the denominator, treats standalone biomass power plants as contributing to power generation, but again, not to CO 2 emissions ( although the CO 2 emitted by biomass co

- fired at coal plants is counted) , and a gain

, biogenic municipal

waste combustion is treated as having zero CO 2 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 g oals. 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 rate s using the same equation and assumptions. We regret the error.3

Table 1

. Summary of how the GHG rule treats CO 2 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

.

B ioenergy does not directly pr ovide “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 CO 2 emissi ons 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 plant s, the ESPS creates target emissions
rates for the existing fleet . These rates, expressed fo r the power sector as a whole, are to be achieved not only by improv ing facility efficiency and taking other measures to control CO 2 emissions at individual existing plants , but also by replacing existing coal

- fired generation with lower

- emitting existing natural gas plants 2 and low

- or zero

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

demand.

Importantly, n either the NSPS nor the ESPS explicitly offer s biomass co

- firing as a means to “reduce” emissions at coal plants . M ost significantly

, all emissions from fossil

- fueled plants

– even emissions from co

fired 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 sta tes 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

- f ired boiler will not be counted.

To promote biomass co

- f i ring 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 CO 2 emissi ons 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 document 4 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 greenhou se 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

- 9.4

“ 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 biomas s 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 engi neering 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 co

firing at coal plants, finding that even if biogenic CO 2 emissions are treated as zero, the “reductions” in

fossil fuel CO 2 emissions at coal plants co

- firing 10% biomass ranges from $30

- $80 per ton of CO 2

. EPA

concludes:

“ Replacing some coal with low levels of biomass co

- firing may resu l t in stack CO 2 increases. Even if biogenic CO 2 emissions are not counted as part of stack emissions, biomass co

- firing is a relatively costly approach to C O 2 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 CO 2 emissions

rates .” 5

While EPA has not offered biomass co

- firing as me ans of reducing greenhouse gas emissions at coal plants, the Agency has st opped 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

T hree years on since EPA’s deferral of regulation of bioenergy CO 2 , and nearly two years since the Scien ce 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

.

Howe ver, t here 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 CO 2 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 .”

A nd

,

“ In its Advisory, the SAB recommen ded 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 f or 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

com ments provided by the SAB and feedback from stakeholders. The EPA’s biogenic CO 2 accounting framework is expected to provide important information regarding the scientific basis for assessing these biomass

- derived fuels and their net atmospheric contributi on of CO 2 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 compl y with the requirements in the emission guidelines

. ”

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

that biomass is carbon neutral

– in contradiction from the SAB report’s clear conclusion, that

“ C arbon 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 t hat 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 biomas s 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, c ounting these emissions as zero can also introduce significant errors into the estimate of present day power sector CO 2 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

- burn ing contribute a significant share of total CO 2 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 w ere 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 po wer 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 s team 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 CO 2 Emissions From Stationary Sources. EPA

- SAB

- 12

- 0 11. 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

t han the facility level, allowing multiple boilers at a single facility to be excluded using different justifications. For in stance, in Maine, Verso Paper was burning natural gas in 2012 at four burners of 15 MW, 24 MW, 72 MW, and 186.8 MW. Although6

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 fuel ed (states with low amounts of biomass/waste in this category may nonetheless have biomass /wa ste 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 state

level 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.7

Florida is the state with the mos t bioenergy/waste emissions excluded from its 2012 emissions total (13.2 million tons). In terms of how CO 2 from biomass and waste burning compares to reported CO 2 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 generati on and power sector CO 2 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 CO 2 emissions from the Maine power sector (tons, and percent

contribution , corresponding to size of pie wedge )

.

In Maine, four f

ossil

- 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 CO 2 , 13% of eGRID’s reported emissions for the state

. Another 28% of reported emissions are contribut ed 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 ar e not connected to the Emissions included

in ESPS 2012

baseline total8

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 fac ilities 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 develo p goal emissions rate s 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 ra te 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

CO 2 /MWh. The second rate adds ge neration from renewable energy to the denominator of fossil

- fueled

rate (MWh) , but still only counts CO 2 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 CO 2 /MWh. 11

In calculating the adjusted rate, EPA counts electricity ge nerated 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 contri bute

CO 2 in the rate equation

- all biomass, waste, and landfill gas burning is treated as emitting zero CO 2 . The system essentially “runs the CO 2 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 emissio ns 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 Ag ency. 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

- ru le

- 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 th e 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 Ne wPage 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,” representin g 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 s how very low levels of biopower sector development . This is because while EPA models

13 http: //www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html10

existing biomass energy facilities as continuing to operate, the model excludes development of new biomass burning facilities as states seek to achieve emissions reductio ns 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 co ntribute 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 implementatio n is indeed essentially flat. As shown in Figure 2, b iopower 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 2020 15 ), 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 Existin g 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; prop osed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 349 31

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” val ues 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.html11

Energy Modeling System (NEMS) to develop its Annual Energy Outlook (AEO). Each year, the AEO “reference case” modeling shows actual energy sector dev elopment for the preceding two years, then forecasts future development . F orecasts 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 pr ojection 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 develo pment 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 r ealities 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 c apacity 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 o f forest wood emitting

18 EPA’s Integrated Planning Model (IPM) modeling files in suppor t 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 CO 2 emission fact ors (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 CO 2 when burned. 19 ( T he modeling still treats biogenic waste burning as having zero emissions.) Under this scheme, any net reductions in lifecycle CO 2 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 , i t 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? C an states still achieve their renewable energy goals with minimal bioenergy ?”

In Maine, as elsewhere, the answer is yes, with the modeling project ing 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 CO 2 emissions in 2030 (while the modeling treats biogenic municipal waste burning as zero emissions, the

19 A previous version of this summary incorrectly state d 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, th e 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 ha s 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 pro visions 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 fossil

fueled 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 biomass

burning 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 e missions 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 deploym ent 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 Tabl e 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 gen eration potential of onshore wind (500 TWh versus 32,700 TWh).

20 See http://www.pfpi.net/wp

- content/upl oads/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 ar e 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 availabili ty 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 fo restry residues 23 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

conta in 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 l ogging, 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 harve sts.” (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 U S 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” CO 2 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 req uire 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 ki lowatt

- 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 th e costs and logistics of biomass co

- firing at coal plants, finding that even if biogenic CO 2 emissions are treated as zero,

the “reductions” in fossil fuel CO 2 emissions at coal plants co

- firing 10% biomass ranges from $30

- $80 per

ton of CO 2 , concluding

“ Replacing some coal with low levels of biomass co

- firing may result in stack CO 2 increases. Even if biogenic CO 2 emissions are not counted as part of stack emissions, biomass co

- firing is a relatively costly approach to CO 2 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 CO 2 emissions

rates .” 28

Combined, fuel costs, infrastructure costs, and maintenance costs can quickly dr ive 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 Pollut ion 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 sugg ests 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 co nsider 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 CO 2 emissions

However, EPA has indicated both in the NSPS and the ESPS r ules 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 suppo rts the concept that burning waste wood and forestry resid ues 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 r ecently issued PSD permi t 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 particu lar biomass feedstocks as a “clean fuel” or “inherently lower emitting” or to engage in a quantitative ranking and comparison of the net atmosph eric 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 Perm it Major Modification for Sierra Pacific Industries

- Anderson Division. April, 2014. Page 10 ( http://www.epa.gov/region9/air/permit/pdf/spi

- anderson/spi

- anderson

- final

permit

- 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, i n 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 dir ection laid out by the most current science, which re cognizes 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, de limbing, 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 pla n 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 a ctually restricted the facility to use of true “waste” wood, m atters of practical implementation would still remain

. E x isting and proposed biomass plants currently do not just

burn waste wood and “residues

, ” 33 and there is a real danger that if wood wast e 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 o f forest wood per year (translating to just over 2 million tons of CO 2 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

- mer chantable 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 P rotection 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 pulpwoo d,” “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 CO 2 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,

m odeling shows that net CO 2 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

. I f 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 i ncrease renewable energy capacity . The Agency i s 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 mea sures that could also lead to CO 2 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 com ment on whether these measures are appropriate to include in a state plan to achieve CO 2 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

tha t 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 t he Science Advisory Board, for EPA to be soliciting

additional comment on whether burning biomass can “reduce” greenho use gas emissions seems somewhat superfluous . The Agency should have more than enough information now to produce a science

- based

carbon ac counting 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 stat es 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 CO 2 emission reduction strategies. We anticipate that states likely will cons ider

biomass

- derived fuels in energy production as a way to mitigate the CO 2 emissions attributed to the energy sector

35 Other Renewable Energy Projects, Covanta website, ( http://www.covantaenergy.com/what

- we

- do/our

- services/other

renewable

- energy.aspx ).

36 http://www.covantaenergy.com/what

- we

- do/our

- services/other

- r enewable

- 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 emissio n guidelines for existing stationary sources: electric generating units; proposed rule. Federal Register Vol. 79 No. 117, June 18 2014, page 3492319

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 acknowledge d 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 fr om 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

ar ound 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)

Unfortunat ely, 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 rate s

. Ranked in descending order of the percent reduction re quired, Washington, South Carolina, Ore gon, 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 es timates, 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 fo rest 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 carbo n 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 is sue 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 po wer 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 term s ) 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 extensiv ely 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 CO 2 per unit energy generated than all fossil fuels. Thus, any claim that bioenergy emits less CO 2 than fossil fuels relies on

39 Ibid, page 34924

40 See http://www.pfpi.net/vermont

- biomass

- power

- plant

- denied

- approval

- on

- basis

- of

- greenhou se

- 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 3488 820

calculation o f net CO 2 emissions over ti me. Li fecycle GHG accounting can show lower net emissions for
biomass than for fossil fuels, based on either the idea that fuels are waste that would decom pose and inevitably emit CO 2 anyway, or that fuels are sourced from forests or crops that can regow and sequester an equivalent amount of CO 2 as emitted by burning. However, as neither process is instantaneous, no biomass energy can be instantaneously carbon neutral.

In fact, b oth justifications for eventual carbon neutrality of biomass energy are es sentially carbon offset

schemes , in that they assume that a process occurring in some other place, and at some future time, compensates for CO 2 emissions from burning biomass now (see Appendix 2 for modeling of typical time periods required for bioenergy C O 2 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 discrimina te 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 C lean 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 o f the court’s reasoning for ruling against EPA’s deferral of biogenic CO 2 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 con current 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 wi th regard to the ability of states to use actual carbon

offsets as a means of mitigating power sector emission s under the GHG rule, whereby, for instance, a forest and its carbon sequestration capacity is preserved to compensate for a fossil fuel plant’s C O 2 emissions . T he 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 progr ams 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 CO 2 emission performance of affected EGUs, be cause 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. I f 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 CO 2 Emission Performance in State Plans. Technical Support Document (TSD) for Carbon

Pollution Emission Guidelines for Existi ng Stationary Sources: Electric Utility Generating Units. Docket ID No. EPA

- HQ

OAR

- 2013

- 0602, June 2014. Page 37.21

The situat ion 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 mate rial 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 wh ether the ESPS rule can count hypothetical reductions in emissions that will occur at som e 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 rule 45

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

Emission Guidelines for Existin g Power Plants Docket ID No. EPA

- HQ

- OAR

- 2013

- 0602. June, 2014.23

Appendix 2 : Technical information on CO 2 from biomass energy

Carbon dioxide emissions from power plants
All fuels produce CO 2 when burned. The general assumption is that all carbon in the fuel i s converted to

CO 2 , though in fact, some small fraction is emitted as carbon monoxide (CO) and other carbon

- containing compounds such as volatile organics.

CO 2 emissions from power plants are typically expressed in units of pounds of CO 2 per megawatt

- hou r of electricity produced (lb CO 2 /MWh).

How much CO 2 does burning wood emit?
Biomass power plants may burn a variety of fuels, including energy crops, crop residues, wood, and “wood

derived 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 CO 2 during combustion is the molecular weight of CO 2 (44) divided by the mo lecular 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 CO 2 :

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

tons CO 2 ÷12 tons carbon = 1.008 tons CO 2

How much CO 2 does a biomass power plant emit?
To compare the amount of CO 2 emitted by biomass power plants versus a same

- sized coal or gas plant, the

CO 2 emissions need to be expressed using a common cur rency, rather than in terms of the pounds or tons

of fuel burned.

The CO 2 per megawatt

- hour produced at any power plant is a function of two main factors:

 The amount of CO 2 emitted by the fuel when it is burned, relative to its energy content, or “heat content” in million Btu (lb CO 2 /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_Combusti on_Lesson_02.pdf) but it is a representative average that is widely used. See for instance http://www.epa.gov/burnwise/workshop2011/WoodCombustion

- Curkeet.pdf24

Coal hea t 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 Gr een wood “as delivered” at a typical moisture content of 45% has a heat content 50 of about 4,730 Btu/lb.

Expressing CO 2 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 CO 2 per MMBtu of energy in the fuel. 51 If biomass facilities were as efficient as coal pla nts, then same

sized facilities would emit similar amounts ofCO 2 . 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 fr om fuel combustion. 53

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

Table 1: CO 2 emissions at the stack for biomass, coal, and natural gas electricity generation 54

Table 1. Per megawatt

- hour, CO 2 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 CO 2 emissions
Just as a biomass plant emits more CO 2 per MWh than a coal plant, co

- firing biomass in a coal plant decreases overall facility efficiency 56 and increases CO 2 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://w ww.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb1205

49 Biomass Energy Data Book 4 th Edition, page 20 5 : http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

50 This is the “higher heating value. ” See page 20 1 of Biomass Energy Data Book 4 th Edition: http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

51 Both emit a great deal more CO 2 per unit energy in the fuel than natural gas.

52 Typica l 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 4 th Editi on, page 20 5 : 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 4 th Edition, page 204: http://cta.ornl.gov/bedb/pdf/BEDB4_Full_Doc.pdf

C O 2 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 o f coal plants. The newest coal plants ar e more efficient.

56 See Electric Power Research Institute report on co

- firing at http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=00000000000100431925

the further the facility’s efficiency will move down th e 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 CO 2 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 material s

- 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 CO 2 , it is argued that burning them as

fue l does not emit more CO 2 than would occur in any case. The problem with this argument is that while burning emits CO 2 instantaneously, wood decomposition takes years to decades.

 The second argument for bioenergy being carbon neutral states that when whol e trees are used as fuel, carbon emissions are “offset” as standing and/or new trees grow and take up an equivalent

amount of CO 2 as was released by burning. The problem with this argument is that burning biomass emits carbon instantly, while regrowth tak es 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 decomp ose anyway” argument
Assuming biomass combustion emissions to be zero because the CO 2 would have been emitted “anyway” from decomposition ignores the fact, highly relevant to calculating the impact of CO 2 emissions on atmospheric CO 2 levels and climate war ming, that burning biomass emits CO 2 instantly, while letting it decompose emits it slowly. Figures 1 and 2 show results from a model 57 of CO 2 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 CO 2 , whereas if
those fuels had been left unburned, CO 2 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

% wo od 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 CO 2 emis sions 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 CO 2 than under the scenario where they are allowed to decompose.

Fi gure 2 shows that same four million tons as the “net” or “additional” CO 2 that is emitted by burning biomass rather than letting it decompose, and shows that this is approximately equal to the CO 2 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 mor e 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 CO 2 emissions from a biomass plant exceed thos e 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” actuall y increase emissions for at least a decade, even compared to inefficient coal plants.

The “Biomass is carbon neutral because forests take up CO 2 ” 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 CO 2 emissions per

year. 58 Forestry activities that cut trees and disturb soils are recognized as sources of CO 2 . Critically, forests take up CO 2 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 CO 2 as was released by burning. However, numer ous scientific studies 59 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 Emissi ons 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 acco unting 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 CO 2 per megawatt

- hour than fossil

- fueled plants, the atmosphere “sees” more power sector CO 2 under a biomass power scenario (that harvests forests and replaces them with seedlings) than it does under a fossil fuel power scen ario (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 CO 2 from new forest growth to bend the net emissions curve for biomass d ownward. 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 CO 2 from a biomass plant than from an equivalen tly 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 CO 2 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 CO 2 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 bio mass 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 e nergy on atmospheric greenhouse gas levels. Journal of Sustainable Forestry, 32:1

- 2, 130

– 158.