Life Cycle Emissions and Cost of
Producing Electricity from Coal,
Natural Gas, and Wood Pellets in
Y I M I N Z H A N G ,†J O N M C K E C H N I E ,†
D E N I S C O R M I E R ,‡R O B E R T L Y N G ,§
W A R R E N M A B E E ,|A K I F U M I O G I N O ,⊥A N D
H E A T H E R L . M A C L E A N *, † , 3
Department of Civil Engineering and School of Public Policy
and Governance, University of Toronto, 35 St. George Street
Toronto, Ontario M5S 1A4, FPInnovations-FERIC, 580 boul.
St-Jean, Pointe-Claire, Quebec H9R 3J9, Ontario Power
Generation, 700 University Avenue, Toronto, Ontario M5G
1X6 School of Policy Studies and Dept. of Geography, Queen’s
University, 423-138 Union St. Kingston, Ontario K7L 3N6, and
National Agriculture and Food Research Organization,
2 Ikenodai, Tsukuba, Ibaraki 305-0901, Japan
Received August 21, 2009. Revised manuscript received
November 19, 2009. Accepted November 20, 2009.
The use of coal is responsible for1/5of global greenhouse
gas (GHG) emissions. Substitution of coal with biomass fuels
these emissions. We investigate, on a life cycle basis, 100%
wood pellet firing and cofiring with coal in two coal generating
stations (GS) in Ontario, Canada. GHG and criteria air pollutant
emissions are compared with current coal and hypothetical
provides the greatest GHG benefit on a kilowatt-hour basis,
reducing emissions by 91% and 78% relative to coal and NGCC
systems, respectively. Compared to coal, using 100% pellets
At $160/metric ton of pellets and $7/GJ natural gas, either
($70 and $47/metric ton of CO2equivalent, respectively). The
at the two GS are responsible for the different options being
overlap in results for all options. A lower pellet price ($100/
metric ton) results in a mitigation cost of $34/metric ton of CO2
equivalent for 10% cofiring at one of the GS. The study
results suggest that biomass utilization in coal GS should be
coal-based electricity in the near term.
“One of the most significant challenges in addressing global
resulting from the use of coal” (1), currently responsible for
countries on coal-fired electricity generation [coal provides
50% of electricity in the US, 80% in China (1), and 40% on
average worldwide (2)], abatement of GHG emissions from
this sector will be challenging but critical to meet targets.
While carbon capture and storage (CCS) will be needed to
make large GHG reductions from coal generation, com-
GHG emissions reductions from coal electricity generation.
One near-term option that can reduce GHG emissions
and be utilized to meet renewable portfolio standards is the
combustion of sustainably produced biomass in coal gen-
erating stations (GS). In contrast to many other renewable
generation options, biomass firing does not have the
drawback of being intermittent and is applicable to areas
without significant wind, solar, or hydropower resources.
Biomass cofiring, where coal and biomass are fired simul-
taneously, generally has a higher fuel cost than coal-only
expenditure by using existing facilities and is applicable for
virtually all types of utility coal boilers. Biomass cofiring has
been shown to reduce SOxand NOxemissions and to result
in net GHG emissions reductions (4). The technology has
other countries but not to our knowledge in Canada. There
pose logistical and operational challenges, primarily due to
differences in coal and biomass properties. There is far less
“repowering”) in prior coal GS, although it has been
successfully implemented in Europe (Electrobel, Belgium)
and in the United States (Schiller Station, NH) and there are
of reported and planned modifications, from changes to
handling systems and coal boilers to full replacement with
a biomass boiler (see Supporting Information).
The Ontario government has committed to eliminating
the use of coal for electricity production by December 31,
2014. In 2007, the province obtained 18% of its electricity
capacity), resulting in ∼28 million metric tons of CO2
equivalent, or 15% of the province’s total GHG emissions
2020, with the largest component of reductions (29%)
expected from actions in the electricity sector (8). Ontario’s
electricity generation capacity is expected to evolve by the
year 2025 from the current mix to one that meets the
government’s supply mix directive (see Supporting Informa-
tion). A doubling of renewable capacity and expansion of
conservation are planned, although exact plans are not
generation (i.e., Ontario’s Green Energy Act 2009, which
is constrained by limited remaining resource availability.
Ontario Power Generation (OPG), which operates four coal-
fired GS, is investigating biomass firing in these stations as
study examines the life cycle (LC) GHG emissions and costs
of biomass options for these GS.
In the United States and Canada (as well as other
†Department of Civil Engineering, University of Toronto.
§Ontario Power Generation.
⊥National Agriculture and Food Research Organization.
3School of Public Policy and Governance, University of Toronto.
Environ. Sci. Technol. 2010, 44, 538–544
5389ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 44, NO. 1, 2010 10.1021/es902555a
2010 American Chemical Society
Published on Web 12/04/2009
due to abundant resources (10). The net benefits of using
biomass will depend upon the activities throughout the LC
of biomass production and combustion, particularly the
biomass properties, fossil energy inputs, fertilizer use (if
employed) and related N2O emissions, and impacts associ-
significantly depending on the LC attributes. Additionally,
the LC performance of the displaced energy system is
important in determining net benefits of biomass. OPG is
focusing on pelletized biomass for use in the coal GS as
pelletization dries and densifies input biomass, producing
and handled and that has better properties for electricity
generation than other forms of biomass. However, pelleti-
energy inputs that may negatively impact the net benefit of
Although life cycle assessments (LCA) of GHG emissions
associated with electricity from biomass coal cofiring have
been completed (12-15), only Damen and Faaij (15) exam-
ined wood pellets (hereafter referred to as pellets) and these
were produced from mill residues, unlike the present study,
which examines dedicated wood harvest for pellet produc-
tion. There have been studies on electricity generation from
biomass use in direct-fired biomass boilers and integrated
gasification combined cycle systems (16, 17) but the studies
did not include economic analyses. Robinson et al. (4)
estimated the cost-effectiveness (CE) of GHG reduction
not LC, emissions. Qin et al. (18) employed a LC approach
and Discussion and Supporting Information, we compare
our results with those of the literature.
100% biomass-fired generation in two of Ontario’s coal GS.
To our knowledge, this is the first study to analyze 100%
biomass usage in a coal GS and to examine dedicated wood
harvest for pellet production. Life cycle GHG and selected
air pollutant emissions are quantified for biomass as well as
reference coal and natural gas electricity generation. The
electricity production costs as well as CE of GHG emissions
mitigation are also estimated, additional contributions to
address gaps in the literature. While site-specific details of
the Ontario case are important, insights from the analysis
can provide guidance for other jurisdictions.
Life cycle inventory (LCI) analysis models are developed to
quantify the relative changes in selected GHG and air
pollutant emissions, for the following Ontario “pathways”:
(1) Reference coal: production of electricity from coal in
two existing coal-fired GS, Nanticoke [3948 MW (net)] and
Atikokan [215 MW (net)].
(2) Reference natural gas: production of electricity from
representative (hypothetical) newly constructed natural gas
combined cycle (NGCC) facility (400 MW).
(3) Pellet cofire: production of electricity at cofire rates of
both 10% and 20% (energy input basis) at Nanticoke and
single unit at Atikokan.
Life cycle costing models are also developed to estimate
the electricity production cost for the above pathways.
LCI Analysis. All LC activities from resource extraction
(e.g., roundwood, coal) and production (e.g., pellet produc-
for the required energy and material inputs were developed
or obtained from databases. Actual operating data for the
in the metrics when switching from coal-only to pellet
combustion or natural-gas-only options, grid electricity
distribution and use are identical for all pathways and
energy inputs needed for equipment manufacture, facility
construction, and labor are not included in the study.
Exclusion of these activities is common practice where it is
expected that these aspects have far smaller implications
than the operations of the facilities (19).
The cofiring pathways are relevant to the time frame 2010
to that time.
The functional unit for the electricity analysis is 1 kWh
are selected GHGs (CO2, CH4, N2O), reported as CO2
equivalents (CO2equiv) based on 100-year global warming
potentials (20), and air pollutant (NOxand SOx) emissions.
The base assumption in this study is that emissions of CO2
resulting from the combustion of biomass are entirely
forest during the time period considered. This assumption
is in line with the treatment of biobased sources in the
as the forest is sustainably managed.
Pellet Production. The pellet production LC activities
include biofiber harvesting, forest renewal, forest road
construction, biofiber transportation to a pellet facility,
pelletization, and pellet delivery to Nanticoke and Atikokan
here, and siting studies are needed to determine locations
of harvest, transportation activities, and facility locations,
best available data at the time of the study are utilized. A
sensitivity analysis was completed on key parameters.
forest management units in the Great Lakes St. Lawrence
The total harvest volume available for pellets supplied from
sustainably managed Crown (public) GLSL forest is ∼1.475
quantities for traditional products but instead would create
a market for available merchantable logs no longer market-
and bioenergy outputs. The present study assumes no
The pelletization process is described in Supporting
Information (Figure S-2). Data on electricity and biofiber
consumption during pelletization were provided by a north-
eastern U.S. pellet producer and reflect a state-of-the-art
facility (pellet capacity 12 ODT/h). The data obtained from
energy use (see Supporting Information) and the use of the
Ontario grid for grid-based electricity]. As data for pellet
production are limited and generally proprietary, the pro-
ducer’s data were verified by comparison with refs 24 and
25. Pellets are shipped to Atikokan exclusively by rail, while
those destined for Nanticoke are shipped by rail to a deep-
VOL. 44, NO. 1, 2010 / ENVIRONMENTAL SCIENCE & TECHNOLOGY 9 539
and ref 24 and would meet specifications stated by ref 26.
Reference Coal and Natural Gas Pathways. The LCI
system boundary for coal-based electricity includes coal
mining and processing, transportation, and combustion in
Nanticoke GS, located on Lake Erie, has eight 490 MWe(net)
with low-NOx burners, two of which are equipped with
by weight) and bituminous Central Appalachian U.S. low-
sulfur (USLS) coal (16% by weight) (27). Atikokan GS, in
with low-NOxburner and uses Canadian lignite coal. The
capacity factors and net coal to electricity conversion
efficiencies are 55% and 35% for Nanticoke and 34% and
33% for Atikokan (27). See Supporting Information, Tables
S-3 and S-6.
The natural gas reference pathway is based on a hypo-
efficiency) (28) located in Ontario, which would receive gas
from Alberta. The LCI activities are natural gas recovery,
processing, transmission and storage, and use in the facility
the coal GS to natural gas boiler or NGCC systems are not
Pellet Cofire Pathways. Emissions associated with elec-
upstream coal and pellet production and transportation
emissions, the amount of each fuel required to produce 1
kWh of electricity, and the emissions from electricity genera-
tion. Cofiring at Nanticoke displaces USLS coal initially and
then PRB coal after all USLS is displaced (27), while cofiring
at Atikokan displaces lignite. To implement cofiring at the
by installing additional conveyors, hoppers, and covered
to the boilers through dedicated silos. Based on tests at the
GS, the estimated heat rate degradation due to cofiring is
at 20% cofire, efficiencies are 34.7% and 32.7%, respectively.
The issue of efficiency loss is of less concern with pellets
because of their low moisture content (5% in this study).
Pellet combustion-related CO2emissions are treated as
zero as per our base assumption. Pellet cofiring is expected
to reduce GS SOxemissions relative to coal-fired generation
reductions are often greater than would be expected from
fuel substitution alone because sulfur in coal can react with
alkali in biomass to form sulfates (29). Reductions in SOx
emissions are estimated on the basis of sulfur contents of
the pellets and coals (reductions beyond those associated
with fuel substitution are not considered). The effects of
cofiring on NOxemissions are more difficult to quantify due
to the complex mechanisms of NOx formation during
combustion. Emissions of NOxcan increase, decrease, or
conditions, and the change in combustion conditions. We
assume cofiring does not yield reductions in NOxemissions
in either of the GS, as tests at Nanticoke reported that NOx
100% Pellet-Fired Pathways. According to OPG, modi-
fications expected at both GS to accommodate 100% pellet
fuel storage (covered) and handling equipment, pulverizers
(replacement or modification of classifiers), and primary air
systems. Detailed engineering studies will determine if
additional modifications are necessary (e.g., to air heater
systems and burners). It is assumed that the units would
operate year-round on pellets. Atikokan’s capacity when
operating with pellets is expected to be close to that when
is estimated to be 5% for 100% pellet operation compared
technical issues, the capacity of Nanticoke’s unit when
when operating with coal. The issues include (1) limited
furnace size (as the units were originally designed for
bituminous coal with a higher energy density than pellets)
and (2) the use of ball-race mills (used to pulverize the fuel);
that result in high pressure differentials that limit their
could be lessened with additional retrofitting. Heat rate
degradation is estimated to be about 10% (27) resulting in
an efficiency of 31.8% (Supporting Information, Table S-6).
No measurements have been made of CH4 and N2O
from ref 28 are used to estimate these emissions. Test data
for 100% pellet firing at Atikokan are utilized for estimating
SOxand NOxemissions for both GS, as no tests have been
completed at Nanticoke. During testing, SO2 emissions
remained below the detectable level of the analyzer for all
firing conditions. We estimate SOxemissions on the basis of
sulfur content of the pellets. A range of NOxemissions rates
is provided by the test data. Data are extrapolated for
Nanticoke GS by assuming the same percentage change in
emissions (from operation on coal) would occur as at
Atikokan. These results are compared with the limited data
available in the literature (Supporting Information, Table
Life Cycle Cost Analysis and Cost-Effectiveness of GHG
Capital (including financing), fixed operating and mainte-
nance (O/M), nonfuel variable O/M, and fuel costs are
considered. The cost of electricity production from coal at
the GS is based on actual operating data, with the capital
costs treated as sunk costs. The NGCC system costs are
estimated from those of a 400 MW advanced NGCC system
(30) and estimates in ref 31. Due to the uncertainty of future
natural gas prices, low, average, and high prices based on
2004-2008 prices are examined (see Supporting Informa-
Biomass cofiring has not been implemented by OPG and
therefore costs are estimated from literature and reviewed
capacity, the midpoint of the range in ref 4. A delivered cost
that estimate the pellet production cost from roundwood in
the GLSL forest for utilization in OPG’s GS.
There is little data publicly available from which to
estimate the cost of converting the GS to 100% biomass, as
not been published. Capital cost estimates in the gray
literature for completed retrofits are ∼$125/kW (Electrobel,
Belgium) and ∼$1500/kW (Schiller Station, NH) of biomass
capacity (calculated from refs 34, 35). The cost difference
reflects the level of retrofit and facility configuration (see
Supporting Information). A retrofit to be completed by
FirstEnergy (R.E. Burger GS, OH) (36) and expected to cost
∼$640/kW of biomass capacity (assuming no capacity loss,
as is claimed by FirstEnergy) matches most closely those
540 9 ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 44, NO. 1, 2010
planned by OPG. On the basis of the above and discussions
analysis (see Supporting Information).
The CE of LC GHG (CO2equivalents) and air pollutant
emissions mitigation (dollars per metric ton) relative to the
reference (coal) pathways through the switch to the pellets
to the significant impact of variability/uncertainty in pellet
and natural gas prices, ranges of these values are examined.
of annual allowable cut) is estimated to be 1.25 million ODT
(1.475 million ODT less biomass used for drying). Imple-
menting 10% cofiring year-round in both GS would require
76% of the pellet supply, while 20% cofiring would require
under the sustainable management plans, assuming no
100% pellets in Atikokan and one unit at Nanticoke would
require 83% of the pellets. These calculations assume
electricity output from the two GS remains at 2007 levels
(Nanticoke 18 210 GWh; Atikokan 652 GWh).
The production of the pellets and their transportation to
either GS results in 0.133 metric ton of CO2equiv/ODT
(Supporting Information, Table S-7). A comparison of our
Information. The forest harvest and pelletization processes
are each responsible for the largest fractions (30% each) of
the GHG emissions associated with pellet production and
transportation. Of the parameters studied, the pellet pro-
duction emissions were found to be most sensitive to the
are generally of high quality and based on actual fuel use,
etc., in GLSL operations (see Supporting Information).
Life Cycle Inventory Results for Electricity Generation.
pellet pathways. Reductions at Nanticoke and Atikokan are
91% and 92%, respectively, compared to the reference coal
pathways. The 100% pellet pathway (in both GS) produces
78% less GHG emissions compared to the NGCC. Displace-
ment of coal or natural gas with a biobased resource such
as pellets results in a large reduction in emissions based on
the assumption that the CO2resulting from the combustion
of the biobased resource is exactly balanced by carbon
incorporated during regrowth of the forest during the time
period considered. The small amount of GS emissions (16 g
of CO2equiv/kWh) in the 100% pellet pathways results from
emissions of non-CO2GHGs. While these results are en-
couraging, to maintain the current GS capacity factors,
be required, and in the case of Nanticoke, a more extensive
retrofit (e.g., replacement of the coal boiler with a biomass
boiler) could be an option. Other sources of electricity or
and demand. The implications of these initiatives would
depend on the LC emissions intensity of the feedstock/
conversion system options utilized.
Compared to the reference coal pathways, the 10% and
20% cofiring rates at both GS result in GHG emissions
reductions of 9% and 18%, respectively (values for a 10%
cofiring rate in the literature range from 6.3% to 9.9%; see
Supporting Information). While cofiring results in lower
emissions than coal-only operation, emissions from the
combustion of a large amount of coal, which has a higher
carbon content than natural gas (25 vs 14 kg of C/GJ). In
spite of the emissions benefits of the NGCC, natural gas is
a fossil fuel that is limited in supply and subject to price
volatility, which are factors of concern if moderate to large
The upstream emissions associated with production of
the fuels are of similar magnitude on a kilowatt-hour basis.
With the exception of the 100% pellet pathways, the vast
majority of LC emissions occur at the GS (resulting from the
combustion of the fuel in the facility).
The GS (facility) emissions of NOxand SOxrepresent the
majority of LC emissions for the coal, NGCC, and cofiring
pathways (Supporting Information, Figures S-4 and S-5).
Compared to coal, both NOxand SOxemissions are reduced
by using 100% pellets; reductions are 40-47% and 76-81%,
respectively. The NGCC pathway also substantially reduces
emissions compared to the coal reference. The cofiring
pathways reduce SOxemissions but result in approximately
the same NOxemissions compared to the coal reference.
Cost of Electricity Production. The coal pathways have
the lowest cost due to their low fuel costs and sunk capital
costs (see Figure 2). Atikokan has higher fixed O/M costs
than Nanticoke, resulting in a higher electricity cost ($42.6
FIGURE 1. Life cycle GHG emissions associated with electricity production through reference, cofiring, and 100% pellet-fired
pathways. Sources of emissions are indicated. Upstream (U/S) and GS fossil emissions for coal and cofiring refer to production and
combustion of coal, respectively; for NGCC, fossil emissions refer to production and combustion of natural gas. CO2 emissions
resulting from biofiber combustion are not included in the figure due to base assumptions.
VOL. 44, NO. 1, 2010 / ENVIRONMENTAL SCIENCE & TECHNOLOGY 9 541
by 0.6 and 0.9 cents/kWh at Nanticoke and Atikokan.
However, even at the lowest natural gas price, the cofire
options have lower electricity costs due to their primary
to the capital cost of new NGCC. The 100% pellet pathways
result in the highest electricity cost due to the pellet cost
and, to a lesser extent, the retrofit cost.
The sensitivity analysis for the Nanticoke 100% pellet
the electricity cost (Supporting Information, Figure S-6).
Capital cost is the next most important variable; an increase
from $640 to $800/kW increases electricity cost by 4%.
Reducing the pellet cost from $160 to $60/metric ton (ref 37
reports a pellet price of $60) lowers the electricity cost by
46%. While a pellet cost this low is unlikely for Ontario, even
if the pellets were produced from “waste” feedstock, some
biomass (unpelletized) is expected to be available at this
cost. Southern Company (38) reports that biomass for their
Georgia facility will be available at a similar cost as coal, and
Walsh (39) reports 192 million and 420 million dry metric
tons could be available in the United States at <$50/metric
and O/M costs and efficiency loss would be incurred at the
Cost-Effectiveness of Emissions Mitigation. At the base
prices ($160/metric ton pellet; $7/GJ natural gas), imple-
and $47/metric ton of CO2equiv, respectively) (Figure 2 and
Supporting Information, Figure S-7). The differences in coal
price, electricity generation cost, and LC emissions at the
two GS are responsible for the different options being
fuel pathways is an aspect that has not received attention in
prior studies but is shown as being of importance here. Our
use of actual operating data for the coal GS highlights the
Cofiring at Atikokan almost doubles the mitigation cost
compared to a NGCC, whereas displacing Nanticoke with a
NGCC has a higher cost than cofiring. Converting the GS to
100% pellet operation are the most costly options. Although
the biomass and NGCC pathways reduce LC SOxemissions
and the 100% pellet and NGCC pathways reduce NOx
emissions, the mitigation costs are very high in comparison
with market prices for these emissions (Supporting Informa-
tion, Table S-10).
The costs of GHG mitigation for the biomass and NGCC
costs resulting from varying pellet prices ($60-$200/metric
ton) and natural gas prices ($5-$11/GJ) are shown in
Supporting Information, Figure S-7. Lower pellet prices of
$125 and $100/metric ton result in mitigation costs of $49
at Nanticoke. While the cofiring and NGCC pathways are
generally more cost-effective than 100% pellet firing, ranges
to be equally cost-effective for the 100% pellet and NGCC
be <$128 and <$65/metric ton for Nanticoke and Atikokan,
respectively. At a pellet price of $160/metric ton, the natural
gas price must be at least $9/GJ (Nanticoke) and $13/GJ
(Atikokan) in order for the 100% pellet and NGCC options
to be equally cost-effective. It is not unrealistic that prices
at these levels could occur in the near future (40). No costs
have been included in our analysis for regulation of fossil-
based GHG emissions under a carbon tax or cap-and-trade
scheme although both the U.S. and Canadian governments
have policies to implement such schemes. If implemented,
the mitigation costs for the NGCC and cofiring scenarios
would increase (options would be less cost-effective for
reducing GHGs) while the 100% pellet option would have
little increase in cost (only that associated with upstream
fossil fuel use).
The costs in the present study are considerably higher
price (Supporting Information, Table S-12). Assuming a low
and likely unrealistic pellet price of $60/metric ton, in line
results in $10 and $31/metric ton of CO2equiv at Nanticoke
and Atikokan, respectively, for both cofiring rates, similar to
the other studies’ results. 100% pellet firing results in $42
and $46/metric ton of CO2equiv at the GS. Comparison with
mitigation costs reported in BIOCAP (41) of $52 and $374/
metric ton of CO2equiv for small-scale wind and solar,
respectively, in Ontario shows that biomass utilization in
coal GS can be competitive with other options, depending
on the scenario and, importantly, the biomass cost.
FIGURE 2. Electricity cost (net of taxes, subsidies, and profit margins) and CE of GHG reduction. Bars represent electricity cost (left
axis). Reference for NGCC for CE is Nanticoke GS coal-only generation. Reference for cofiring CE is coal-only operation at
542 9 ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 44, NO. 1, 2010
Although Canada is one of the world leaders in pellet
the GLSL forest would almost double the country’s produc-
would provide 2.5 TWh/year of renewable electricity, 1.6%
of Ontario’s total electricity supply, and reduce GHG emis-
sions by 2.1 million metric tons of CO2equiv [7% reduction
in the province’s electricity generation emissions (based on
2007 generation)]. This puts into perspective the magnitude
of electricity consumption relative to the availability of the
GLSL biomass resource. A combination of conservation,
efficiency improvement, and renewables would be needed
to make significant progress in reducing electricity sector
emissions. It was beyond the scope of this study to examine
all potential generation options and to determine the
of techno-economic, environmental, social, risk, and insti-
other jurisdictions. The results suggest that electricity
produced from biomass in existing coal GS should be
considered, along with other alternatives, as a means of
as well as the fuel costs were found to significantly impact
are technical and cost trade-offs associated with the use of
roundwood versus “wastes”/residues for pellet production
and as well between pelletized and unpelletized biomass.
Local studies are needed to understand coal GS character-
The following simplistic calculations do not reflect the local
nature of these aspects or a host of other issues but are
provided for perspective. If 10% cofiring were to be imple-
mented in all coal GS in the United States and Canada (60%
could contribute approximately 4% of annual generation of
by 170 million metric tons/year, ∼5% of emissions from the
two countries’ electricity sectors (7, 43). This would require
∼2000 PJ/year [∼100 million metric tons (dry)] of biomass,
a large amount but within inventory amounts in ref 39.
With biomass, as with any resource, large-scale imple-
only if policies are enacted that steer biofuels in the “right
direction” and if environmentally sustainable practices are
employed throughout the LC (44). The Intergovernmental
Panel on Climate Change recognizes the potential contribu-
tion of forests in reducing GHG emissions through main-
taining or increasing forest carbon storage as well as
sustainably producing fiber, timber, and energy products
(21). Displacement of coal with biomass results in consider-
able reductions in CO2emissions in large part due to the
for pellet production, while still within sustainable harvest
A full accounting of the GHG balance of biomass use should
include resulting changes in forest carbon (45): further
modeling examining forest carbon is recommended.
In addition to the issues examined, additional consid-
erations (other environmental, public perception, techno-
logical, and regulatory aspects) must be studied prior to
implementation. There are nonbiomass options to meet
renewable energy and GHG reduction goals, and other
renewable electricity generation technologies, all with their
if these achieve much higher penetration in the near future,
they would in most cases still represent a modest portion of
peak demand. Hydro is the exception in a small number of
countries but there are limited sites. Biomass utilization in
coal GS can follow load and be integrated into the existing
There is promise of carbon capture and storage but uncer-
and time frame for implementation. Biomass utilization in
coal GS should be considered for its potential to mitigate
GHGs from the electricity sector in the near term. Climate
change is a critical issue, and delaying the implementation
of abatement measures will be costly.
and Engineering Research Council. We thank the pellet
producer and the Ontario Ministries of Natural Resources
and the Environment for data and insights for the study.
Supporting Information Available
Details on electricity generation in Ontario, conversion of
results and discussion. This information is available free of
charge via the Internet at http://pubs.acs.org/.
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