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OPERATION ECONOMY OF CHP PLANTS USING FOREST BIOMASS AND PEAT
M. Hurskainen, J. Kärki & J. Raitila
VTT Technical Research Centre of Finland Ltd
P.O.Box 1603, FIN-40101 Jyväskylä, FINLAND
Janne.Karki@vtt.fi, tel. +358 20 722 2549, fax +358 14 617058
ABSTRACT: In Finland most of the combined heat and power (CHP) plants are based on fluidized bed combustion
and are co-combusting different types of woody biomass with peat. Due to the CO2 emission reduction targets and
subsequent renewable energy support mechanisms, the share of biomass has been increasing. Biomass utilization can
increase plant’s operational costs through higher fuel costs and negative effects on efficiency and availability of the
boiler and increased maintenance work. The economic feasibility of biomass utilization is then dependent on whether
the policy support measures make up for the additional costs. An interactive toolkit was developed to help to
understand the relevance of various factors affecting the operation economics of a multifuel CHP plant and to study
the respective competitiveness of peat and different types of forest biomass. In the fictional case example co-
combustion of forest biomass and peat was found to be more feasible option than using either peat or forest biomass
alone in the current market situation. Co-combustion provides synergy effects which decrease the O&M costs. The
current low price of CO2 emission allowances makes biomass utilization dependent on the subsidies. The
competitiveness between biomass and peat is also naturally strongly affected by the relative fuel price developments.
Keywords: biomass, cocombustion, combined heat and power generation (CHP), costs, economics, fluidized bed
1 INTRODUCTION
The need to cut down CO2 emissions and subsequent
renewable energy support schemes have encouraged
power plant operators to broaden their fuel palette from
fossil fuels to include various types of biomasses, which
are considered carbon neutral, at least for the time being.
In Finland most of the combined heat and power (CHP)
plants today are based on fluidized bed combustion and
are co-combusting different types of woody biomass and
peat. The share of biomass has been increasing in many
plants in recent years and a few large-scale plants have –
at times – been running on 100% biomass. In 2013 18.7
million cubic meters of wood fuels were used for energy
production in heating and power plants in Finland. About
8 million cubic meters of that were forest chips,
consisting of chips made from logging residues, stumps
and small diameter thinning wood [1]. In their climate
and energy policy for 2020 [2], the Finnish Government
has set a goal to increase the use of forest fuels to 13.5
million cubic meters annually.
Biomass utilization typically incurs additional
expenses which are associated mainly with higher prices
of biomass fuels in comparison to fossil fuels, higher
plant investment and O&M costs. The economic
feasibility of biomass utilization in the plant operator’s
point of view is then dependent on whether the policy
support measures make up for the additional costs. The
level of these additional costs is highly affected, not only
by the fuels considered, but also by the boiler technology
and design. Typically, the fuel properties of biomass are
worse than those of their fossil counterparts, causing
dedicated biomass power plants to have lower
efficiencies and higher O&M costs. Co-combustion –
defined as the simultaneous combustion of two or more
fuels in the same boiler – makes it possible to utilize the
synergy effects between fossil and biomass fuels to
reduce the costs and penalties associated to biomass
utilization. In general, fluidized bed boilers offer the best
fuel flexibility for co-combustion. In properly designed
circulating fluidized bed (CFB) boilers, biomass fuels can
be used with coal or peat at any percentage from 0–100%
[3,4]. Bubbling fluidized bed (BFB) boilers are best
suited for moist fuels containing high amount of volatiles
[5], limiting their capability to utilize coal. Power plants
with high fuel flexibility can adapt to the prevailing fuel
market by optimizing the fuel mix accordingly.
The purpose of this work was to create an interactive
tool which could be used for studying the operation
economics of a CHP plant when different fuels relevant
to Finland are used. The operation economics are affected
by various factors such as investment costs, fuel prices,
operation and maintenance (O&M) costs, values of
produced electricity and heat, subsidies, taxes and the EU
Emission Trading Scheme (EU ETS) [6]. The idea behind
the tool is to allow the user to change for example market
values and plant or fuel specifications and to see how the
changes affect the operation economics in an illustrative
way. The BFB combustion technology was chosen for
this case and the fuels included peat and three types of
biomass: forest (logging) residues, small diameter stem
wood and stumps. Biomass fuel supply chains were
included to illustrate the effect of biomass availability
and demand on transport distances and, thus also road
transport costs. Detailed investment feasibility
evaluations were out of the scope of this work.
In this paper the main differences in fuel properties
between peat and forest biomass – and the implications of
these differences on boiler design and operation – are
discussed first, which is followed by a short description
of the Finnish biomass policy framework. In the second
part the developed tool is first briefly presented after
which it is used for a fictional case example in which
three cases are compared: 100% biomass, 100% peat and
co-combustion at 70% biomass share.
2 NORDIC WOODY BIOMASS VS PEAT AS A FUEL
Due to differences in fuel properties between peat
and woody biomass (Tables I&II), and in lesser extent
also between different woody biomass types, the selected
fuel blend affects the plant design, investment required,
and operational parameters such as boiler efficiency,
plant availability and operation and maintenance costs.
Although Nordic woody biomass is clearly a higher
quality fuel compared to many agro biomass or waste
fuels, it is still known to cause some ash related
challenges in fluidized bed plants if it is used as the only
fuel (or if its share is very high) (Fig. 1). Due to relatively
high concentration of reactive alkalis (mainly potassium)
and the lack of so called protective compounds in woody
biomass, there is an elevated risk of bed material
agglomeration, boiler fouling and even chlorine induced
hot corrosion of the superheaters [7–11] although
chlorine content of Nordic woody biomass is low (Table
I). The protective compounds help to prevent
disturbances in boiler operation and material damages by
altering the ash chemistry. They transform harmful
components, formed from biomass (and waste) fuels, into
less harmful or completely harmless form. Sulphur
compounds and aluminum silicates are the most
important protective compounds. Fossil fuels – such as
coal and peat – contain these protective compounds
inherently. Thus, when woody biomass is co-combusted
with peat the problems related to using biomass
combustion can be mitigated, simultaneously decreasing
the high SO2 emissions from peat combustion [7,12]. If it
is not possible or viable to adopt co-combustion,
protective compounds can be added as additives such as
elemental sulphur, different sulphates or kaolin/china
clay [13–17].
In addition, handling and flow properties of forest
biomass fuels are usually poor due to particle size
variation and high fiber and over-sized particle content
which sets high requirements for handling and feeding
equipment [18]. At winter time, high moisture biomass
tends to freeze more easily causing extra challenges.
Generally speaking, chipped fuels have better handling
properties than hogged fuels due to more even particle
size distribution and a more favorable shape of particles.
Hogged fuels tend to have long and narrow particles
which can cause e.g. arching in silos and limit the
capacity of the fuel feeding lines. [19]
Table I: Main fuel properties of peat and Nordic forest
biomass [19]
Property Unit Milled
peat Woody
biomass
Moisture wt% 45–48 45–55
Volatiles wt% (d) 63–73 84–88
Ash content wt% (d) 4–8 0.5–4.0
Net calorific
value(NCV) MJ/kg (d) 19–23 19–20
Net calorific
value as rec. MJ/kg 8.5–11.5 7.5–10.0
C
H
N
S
Cl
wt% (d)
50–57
5.1–6.1
0.9–2.4
0.1–0.4
0.02–0.06
48–52
5.5–6.0
0.2–0.5
0.02–0.05
0.001–0.04
(d)=dry basis
Table II: Typical ash composition of peat and wood
(pine) [19]
Oxide Unit Peat Pine
K2O
wt-% (d)
1.0 12.0
Na2O0.5 3.0
CaO 13.0 42.0
MgO 3.0 12.0
P2O54.0 5.0
Al2O316.0 2.0
Fe2O323.0 5.5
SiO239.0 8.0*
TiO20.5 0.1
SO33.0 4.5
*strongly dependent on the amount of sand/soil
impurities
Figure 1: Solid fuel ranking based on heating values and
challenges imposed on boiler design (Courtesy of Amec
Foster Wheeler)
The required additional investment when using
biomass is caused by several factors. For example the
boiler needs to be slightly larger (due to the lower as-
received calorific value and higher moisture content of
biomass), biomass handling and feeding equipment is
more complex and it might be necessary to use higher
quality (=more expensive) heat transfer surface materials
to prevent high temperature corrosion and install more
advanced coarse bed material removal systems.
Additional O&M costs for forest biomass utilization
in CHP plants are typically due to e.g.:
·More fuel feeding related problems affecting
the availability of the boiler à District heat (or
process steam) must be generated by other
more expensive means. Typically this means
fuel oil fired heating plants and therefore also a
loss of income from electricity sales
·Increased boiler fouling at high biomass shares
à more frequent soot-blowing à loss of
efficiency and increased boiler water
consumption and possibly faster wear and tear
of the heat transfer surfaces
·Slightly lower boiler efficiency (and capacity)
with high moisture biomass
·More frequent maintenance of fuel feeding
equipment and boiler components
·Extra manpower related to fuel procurement,
handling, quality control etc.
·Increased make-up bed sand consumption
·When 100% biomass is used, additives such as
elemental sulphur are typically needed in order
to prevent chlorine-induced superheater
corrosion
·In case of BFB boilers, when biomass fuels are
drier than expected, it is sometimes necessary
to cool the bed area by spraying water directly
into the bed à high heat energy loss (if there is
no flue gas condenser)
Biomass utilization can also bring some savings in
O&M costs:
·The amount of ashes generated is reduced
(there can also be changes in possible
utilization applications which could provide
additional income or cause extra costs)
·Less limestone is required to meet SO2
emission limit or there is no need at all
depending on the co-combustion share.
The extents of the above mentioned phenomena
depend not only on the biomass co-combustion shares but
also on the types of woody biomass used. Due to
enrichment of minerals in needles, forest residues
typically contain the highest amounts of alkalis and
chlorine [19] which indicates the highest fouling,
corrosion and agglomeration tendencies among forest
biomasses. Stumps on the other hand contain elevated
amounts of sand/soil impurities [19] which cause faster
wearing of the fuel handling and feeding equipment and
may lead to more interruptions in fuel feeding. Chips
made from small diameter wood represent a high quality
forest biomass having good handling characteristics and
low levels of harmful compounds. The properties of the
supplementary fuel (e.g. peat or coal) and the boiler
design will naturally also play a role.
3 POLICY FRAMEWORK FOR BIOMASS
UTILISATION IN FINLAND
3.1 Energy taxes
In Finland energy taxes are levied on electricity, coal,
natural gas, fuel peat, tall oil [20] (1260/1996. Act on
Excise Tax on Electricity and Certain Fuels) and liquid
fuels (1472/1994. Act on Excise Tax on Liquid Fuels)
[21].
Only the fossil fuels used in heat production are
subject to taxes – fuels for electricity production are tax
exempt. For heat production, the taxation of fossil fuels is
based on their energy content and specific CO2
emissions. In addition, a small ‘strategic stockpile fee‘, is
levied. CHP production gets a tax relief compared to
heat-only production. As CHP plants typically fall within
the EU ETS, the CO2 component tax is only 50% of the
corresponding heat-only plant’s tax to reduce the overlap
between the two steering mechanisms. Furthermore, in
CHP production the total heat tax (called excise tax) is
paid only from the amount of fuel corresponding to the
quantity of produced heat times a factor 0.9. The tax
treatment of peat differs from other fossil fuels. For peat,
taxation is not based on energy content or specific
emissions but an ‘energy tax’ with a fixed level is levied.
From March 2016 onwards this has been 1.9 €/MWh
(was lowered from 3.4 €/MWh). Taxation of peat is a lot
lighter compared to other fossil fuels (Table III).
Table III: Excise taxes for fossil fuels used in the
production of heat in Finland (2016)
Fuel Heat-only plants
(€/MWh) CHP plants
(€/MWh)
Coal 25.21 16.01
Natural gas 17.42 12.08
Heavy fuel oil 22.22 14.56
Peat 1.90* 1.90*
*3/2016 onwards
3.2. Renewable electricity production subsidies
The Act on Production Subsidy for Electricity
Produced from Renewable Energy Sources (1396/2010)
[22] and Decree on Production Subsidy for Electricity
Produced from Renewable Energy Sources (1397/2010)
[23] set the requirements for wind, biogas, forest chips
and woody biomass based power plant acceptance to
subsidy mechanism and the levels of the subsidies.
Large-scale biomass based electricity production is
supported by a feed-in premium mechanism. The level of
feed-in premium is dependent on the CO2 emission
allowance price and the excise tax of peat as shown in
Fig. 2. The applicable biomass types are limited to those
‘delivered directly from forests’ (branches, tops, stumps,
small diameter wood, etc.). Thus, by-product biomasses
such as residues from wood and forest industries (bark,
sawdust, chips for pulp mills) are not eligible. For forest
chips produced from wood suitable for forest industry
(pulp or sawmills) and which originate from forest stands
consisting of wood classified as ’large sized
merchantable wood’, the tariff is 60% of the normal
level. This regulation was adopted to ensure that wood
suitable for forest industry will not be used as energy.
Figure 2: Feed-in premium for forest biomass based
electricity generation in Finland (3/2016 onwards)
3.3 The EU Emission Trading Scheme
The EU ETS is the world’s largest emission
allowance trading scheme and the cornerstone of the
EU’s drive to reduce CO2 emissions. The EU ETS works
by setting an annually decreasing cap for the CO2
emissions that the participating installations can emit.
Within the cap, participants receive or buy European
Emission Allowances (EUAs) which can then be traded
with one another. The EU ETS includes more than
11,000 power and industrial plants and it covers around
45% of the total emissions from the participating
countries. [6]
The EU ETS covers combustion plants whose rated
thermal inputs are over 20 MW (with the exception of
hazardous and municipal waste incinerators). Basically
all Finnish CHP plants have > 20 MW thermal inputs and
thus they will have to obtain EUAs for the emitted fossil-
based CO2. In the third trading period (2013–2020),
electricity production is no more eligible for free
allowances but CHP plants can get free allowances for
the heat production part. The base amount of free credits
is determined by the benchmark specific emission level
(62.3 EUA/TJheat) which is based on using natural gas as
the fuel (or by the plant’s historical emissions). The total
amount of free allowances decreases each year (except
for carbon leakage sectors). In 2013 heat production
received 80% of the benchmark plants emissions for free
but in 2020 this will be only 30% [24]. If a plant gets
more free allowances than it needs, they can be sold in
the markets for an extra profit.
4 INTERACTIVE TOOL FOR STUDYING THE
OPERATION ECONOMICS OF CHP PLANTS
Three CHP plant cases utilizing different fuels are
compared in the tool: 1) plant using 100% peat, 2) plant
using 100% biomass and 3) plant co-combusting peat and
biomass on a user-specifiable share and with user-
specifiable biomass types. The cases are compared with
respect to annual costs and incomes by taking into
account all the relevant factors affecting the CHP
economics. Every parameter having this figure is user-
adjustable: (spinner).
The tool consists of eight tabs:
·Plant specifications
·Biomass supply
·Biomass availability
·O&M
·Annual costs
·Costs vs CO2 price
·Profits
·CO2 emissions.
In the Plant specifications tab (Fig. 3) the user can
specify various plant related parameters such as
capacities, efficiencies, fuels and specific investment
costs. Based on the input values, electricity and district
heat outputs (MW) and annual productions and fuel
consumptions (GWh/a) are calculated.
Figure 3: Plant specifications tab
The main purpose of the Biomass supply tab (Fig. 4)
is to calculate the average cost of biomass at the power
plant gate with given parameters such as the shares and
properties of different biomass types and their
availabilities at the plant location. Transportation
distances (and thereby also the costs) are calculated based
on the biomass availabilities and annual biomass
demands of the plants. The shape of the supply area and
winding of roads are taken into account. The
availabilities can be estimated using maps on the Biomass
availability tab.
In addition, there is a ‘biomass challenge level
indicator’ which indicates the possible challenges the
selected biomass mixture (forest residues/small diameter
wood/stumps) poses to boiler operation – as mentioned
before: different forest biomass fractions are not alike.
The effects of these challenges on operation and
maintenance costs (fixed and variable) are then illustrated
in the O&M tab. The O&M costs are presented also as a
function of total biomass co-combustion share. The
O&M costs are assumed first to decrease when adding
biomass (mostly due to savings in limestone injection
costs) but at high biomass shares the adverse effects of
biomass will cause O&M costs to increase compared to
operation on peat. The costs will increase more quickly
with forest residues and stumps compared to small
diameter wood. The O&M cost estimations are based on
VTT’s practical experience on biomass co-combustion in
large-scale fluidized bed boilers. The equations used in
the tool for both variable and fixed O&M costs as a
function of share of biomass are obtained by fitting to
data, which has been collected from certain power plants
utilizing high proportions of biomass. For this study,
these equations were fine-tuned to better represent the
situation in new plants.
Figure 4: Biomass supply tab
The Annual costs tab (Fig. 5) shows the cost
breakdowns and total annual costs for the three cases.
The costs are divided into fuel purchase, O&M (sum of
fixed and variable), capital expenses (CAPEX), taxes,
subsidies (as negative cost) and CO2 emission allowance
trading. Many variables, such as fuel prices and levels of
subsidies/taxes and CO2 emissions allowances, can be
changed by the user and their effect can be seen instantly.
The effect of CO2 emission allowance price on total costs
in each case is illustrated further in the Costs vs CO2
price tab.
Figure 5: Annual costs tab
In the Profits tab the annual profits, incomes and
costs are presented. The profits are dependent on the
prices obtainable for electricity and district heat (or more
precisely the energy components of electricity and district
heat), which can be specified together with the assumed
losses in the district heating network. Income is equal in
all the three cases as the plant outputs are fixed. The
changes in plant availability, extra soot-blowing etc. are
allocated to O&M costs rather than annual energy
production figures. The purpose of the profitability
evaluations is to allow studying at which market
conditions, plants could make profit. As mentioned
before, detailed investment feasibility evaluations were
out of the scope of this work. If the feasibility of the
investment would need to be evaluated, more detailed
scenarios with price escalations for fuels, electricity, heat
and O&M costs and possible changes in support schemes
should be incorporated and corporate taxes and financing
structure should be taken into account.
The CO2 emissions tab (Figure 8) shows the CO2
emissions which have been divided into free emission
allowances and allowances that must be bought (or can
be sold) for each case. There is a possibility to give
biomass a non-zero emission factor if forest biomass will
not be considered 100% CO2 neutral anymore in the
future.
5 CASE EXAMPLE
5.1 Description and assumptions
As a case example, plant with fuel power of 100 MW
with 85% CHP efficiency and 0.45 power-to-heat ratio is
considered. The plant produces electricity to the grid and
district heat for a fictional small town. The total
production corresponds to annual peak load utilization
hours of 5,500.
In the co-combustion case, the share of biomass (on
energy basis) is 70% while the other two cases are 100%
biomass and 100% peat. The 100% peat case should be
considered just a theoretical reference case – today no
one would actually invest in a plant that would operate
only on 100% peat. The main purpose is to compare the
respective competitiveness of the three cases in different
market situations rather than evaluate the total economic
feasibility of the investments.
The biomass fuel fractions (on energy basis) for both
co-combustion and 100% biomass cases are as follows:
·50% forest residues
·40% small diameter wood
·10% stumps.
The comminution of wood is assumed to take place at
road-side by mobile chippers or grinders, and the wood
chips are assumed to be delivered using trucks with load
capacities of 120 m3 and 40 t. In this case, the loads are
limited by volume for every biomass type. The economic
availabilities of the forest biomasses at the plant location
are 6, 4 and 2 solid-m3/km2 for the forest residues, small
diameter wood and stumps, respectively. The plant is
considered to be located inland so the shape of supply
area is assumed to be circular. Biomass prices will be
calculated based on based on biomass availabilities and
demands. For peat, a fixed price of 14 €/MWh is used.
The price of milled peat delivered to the plant has
remained quite constant at 13.5–14.5 €/MWh (excl.
taxes) for the last few years [25]. The assumed main fuel
properties are listed in Table IV.
Table IV: The assumed main fuel properties
Fuel NCV
MJ/kg (d) Moisture,
wt%
Ash
content,
wt% (d)
Forest residues 20.0 50 3.0
Small diameter
wood 19.5 40 1.5
Stumps 19.0 35 6.0
Peat 21.0 45 5.0
(d) = dry basis
Specific investment costs have been set based on the
most recent public press releases for similar-sized CHP
plant investments in Finland and estimating the cost
difference between peat and biomass fired units. Capital
costs are annualized considering economic lifetime of 25
years and discount rate of 6% in real terms (inflation
compensated).
The prices for electricity, district heat and emission
allowances represent closely the current (2016) market
situation. The average wholesale price of electricity
(Nord Pool, Elspot, Finland’s area price) was 29.7
€/MWh in 2015 and 29.6 €/MWh for Jan–Apr 2016 [26].
For district heat each distributor can set the price.
Some distributors have seasonal pricing mechanisms
where the price is lower in summer time. In networks,
where heat is produced mostly in CHP plants, the
weighted average energy component price of district heat
was 48 €/MWh (excl. VAT) in 1/2016 [27]. Seasonal
pricing has been taken into account in the above
mentioned average price by using a typical monthly
district heat consumption distribution. If the same
distribution is used also for electricity, the average price
for 2015 would increase to 30.5 €/MWh.
In 2016 the price of emission allowances have been
5–8 €/t [28] and the amount of free allowance for heat
production corresponds roughly to 60% of the benchmark
plant’s emissions.
The key assumptions are summarized in Table V.
Table V: Key assumptions for the case example
Property Value
Fuel power 100 MW
CHP efficiency (LHV, net)* 85%
Power-to-heat ratio (net)* 0.45
Peak load utilization hours 5500 h/a
Specific investment cost (as peat
fired unit) 800 €/kWfuel
Extra investment for biomass 50 €/kW
fuel, biomass
Economic lifetime 25 years
Discount rate (real terms) 6%
Electricity (energy component) 30 €/MWh
District heat (energy component) 50 €/MWh
District heat network losses 8%
Peat (excl. excise tax, incl.trans.) 14 €/MWh
Biomass Calculated
Energy taxation and subsidies Finland, 2016
EU emission allowances (EUAs) 6.5 €/tCO
2
Share of free EUAs (of natural
gas based generation emissions) 60%
*excluding district heat network losses
5.1 Biomass prices at the CHP plant
The biomass gate prices and price breakdowns for the
co-combustion case are shown in Fig. 6. Typical values
have been used for all the other cost categories with the
exception of transportation costs which were calculated
based on biomass availabilities and demands. Average
transport distances were 47–68 km depending on the
biomass type. Small diameter wood is clearly the most
costly biomass type. The low share of raw material cost
on total costs is characteristic to forest biomass.
Harvesting is the single most significant cost factor
followed by chipping and transportation.
Due to higher biomass demand, the average transport
distances are longer (56–81 km) for the 100% biomass
case (Fig. 7) leading to 0.3–0.5 €/MWh higher biomass
prices depending on the biomass fraction. Other cost
categories are equal to the co-combustion case.
The weighted average biomass prices at the power
plant gate are 21.1 and 21.5 €/MWh for co-combustion
and 100% biomass cases, respectively.
Figure 6: Biomass price breakdowns for the co-
combustion case
Figure 7: Biomass transport costs (includes loading and
unloading) for co-combustion and 100% biomass cases
5.2 Annual costs
The annual cost breakdowns and total costs for each
case are shown in Fig. 8. As the total income from
electricity and district heat is equal in every case and
because biomass subsidies are considered as negative
costs (see chapter 4), the least cost option is also the most
profitable one.
With the assumed values, the co-combustion case has
the lowest total annual costs followed closely by the
100% peat case. Thus, the synergy effects of co-
combustion more than overcame the higher costs of
biomass utilization in the considered case. However,
without subsidies the plant firing 100% peat would be the
most profitable option.
The most significant cost categories are fuel purchase
and capital expenses while taxes and the EU emission
trading have only minor effects in the current market
situation. At the present moment the price of emission
allowances is low. Also the taxation of peat is very light
compared to other fossil fuels such as coal (Table III).
When comparing the respective competitiveness between
peat and biomass, fuel and emission allowance prices are
the two most interesting factors. The price of emission
allowances will also affect the feed-in premium levels for
the bio-based electricity.
Figure 8: Annual CHP plant operational costs
Fig. 9 illustrates the effect of emission allowance
price on the respective profitability of the considered
cases. The peculiar shapes of the co-combustion and
100% biomass case graphs are due to the CO2 price
dependent feed-in premium mechanism (Fig. 2). The
100% peat case is most profitable when CO2 price is less
than ~6 €/t after which the co-combustion case becomes
the least cost option. When CO2 price rises above ~29 €/t,
the 100% biomass case overtakes the co-combustion
case. Due to the feed-in premium there is not much
difference between the cases when the EUA price is in
the range of 10–23 €/t.
Figure 9: The effect of CO2 emission allowance price on
the respective profitability of the studied cases
Fig. 10 shows how the changes in average biomass
prices affects the respective competitiveness when price
of peat like the all the other parameters stay constant.
Biomass price should decrease by ~3.5 €/MWh to make
the 100% biomass case the most feasible option. To
overtake the 100% peat case, a price drop of ~1 €/MWh
would be sufficient. However, there is a lot more pressure
for biomass prices to increase in future than there is for
them to get lower. If biomass prices increase by as little
as ~0.2 €/MWh, the 100% peat case becomes the most
favorable option. The co-combustion case is most cost
competitive one when the average biomass price stays
within -3.5–0.2 €/MWh of the levels calculated in this
study. Thus, biomass prices cannot increase much or else
using peat would be more tempting. This is not an
unexpected result as the feed-in premium for forest
biomass based electricity is meant to make biomass the
preferential fuel but without granting unnecessarily
generous support.
Figure 10: The effect of biomass price on the respective
profitability of the studied cases
5.3 Overall profitability
The annual costs, income and profits for each case
are shown in Fig. 11. In the considered case, the annual
pre-tax profits ranged from ~0.7 M€ for the 100%
biomass case to ~1.3 M€ for the co-combustion case.
These would lead to pre-tax payback periods in the range
of 17.5–20.5 years assuming that the costs and income
will stay constant (in real terms) for the whole
operational period. The analysis here is over-simplified
but it indicates that the investments could be just about
feasible (economic lifetime was 25 years) and that the
differences between the cases are not very marked.
Notably almost 80% of the income is from district
heat sales. In Finland, the current ‘reversed’ prices of
electricity and district heat (in CHP’s point of view) have
caused a pressure to invest in heat-only plants instead of
CHP plants. The feed-in premium for forest biomass
based electricity might not be enough to tip the scales in
favor of a CHP plant. As far as resource efficiency goes,
heat-only production instead of CHP is not a favorable
trend.
Figure 11: Annual incomes, costs and profits
4 DISCUSSION
The interactive tool approach helps to understand
how the fuel qualities, plant specifications or market and
policy related aspects affect the operation economics of
CHP plants and enables the users to conduct their own
studies without having to be experts on e.g. fluidized bed
combustion. Users that could benefit from such tools
include e.g. power plant operators/investors, fuel
procurers, people responsible for energy policies,
consultants, researchers and teachers. For each purpose a
tailor-made toolkit can be created. For example more
detailed financial models and price escalation scenarios
could be implemented for power plant investors while for
energy policy or taxation studies, more fuels and plant
types could be added.
Currently the main uncertainties of this tool are
related to the O&M cost estimations. There is only a
limited amount of detailed data on how forest biomass
co-combustion affects the costs, let alone data on
difference between different forest biomass types. This is
due to the fact that this kind of data is difficult to obtain
taking into account all the variables in the operation of a
CHP plant (e.g. constantly changing fuel mixtures, fuel
qualities, weather, loads). Also the effects such as more
rapid deterioration of some boiler components and fuel
handling equipment can be noticed only after long time
spans and thus, it is basically almost impossible to
allocate the additional costs to any specific fuel type.
Furthermore, even if this kind of data did exist, plant
owners can consider it a trade secret. In addition, there
can be marked differences between plants as the fuel
feeding systems and boilers are not the same: the equal
quality biomass might cause various operational
problems in some plants while some might have no
problems whatsoever. Naturally, the plants that have been
designed from the beginning to use high shares of forest
biomass will likely run into fewer problems than plants
which have had to change their fuel blends markedly.
If more detailed data is available, or if there is a more
concrete case plant than the generic example used in this
study, more accurate O&M cost estimations can be easily
implemented into the tool.
5 CONCLUSIONS
Operation economy of a multifuel CHP plant is
affected by many technical, market and legislation related
factors. The developed interactive toolkit will help to
understand the relevance of each factor and it provides a
means to study the respective competitiveness of peat and
different forest biomass types in fluidized bed plants in
Finland. In the fictional case example co-combustion of
forest biomass and peat was found to be more feasible
option than using either peat or forest biomass at 100%
shares in the current market situation. Co-combustion
offers synergy effects which can decrease the O&M
costs. At the current low CO2 emission allowance prices,
biomass utilization is dependent on the subsidies. The
relative competitiveness between biomass and peat is also
naturally highly dependent on the development of fuel
prices.
5 ACKNOWLEDGEMENTS
·This work was carried out mostly in the
Sustainable Bioenergy Solutions for Tomorrow
(BEST) research program coordinated by CLIC
Ltd with funding from the Finnish Funding
Agency for Technology and Innovation, Tekes.
The financers are sincerely acknowledged.
·The authors want to acknowledge also Matti
Virkkunen from VTT Technical Research
Centre of Finland Ltd for his support.
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