Industrial self generation a cross-commodity hedge
in the EU emissions trading
Georg Rosenbauer & Harald Dichtl
Siemens Power Generation
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Industrial self generation a cross-commodity hedge
in the EU emissions trading
Georg Rosenbauer & Harald Dichtl
Siemens Power Generation
The EU Emissions Trading Scheme (EU ETS) bears various uncertainties and price risks for
the commodities CO2, power and fuel. However, real life cases and the insight into market
mechanisms show that industrial self generation is a valuable cross-commodity hedge against
these risks.
Example:
Combined cycle plant with steam extraction
122 MW el – 75 MW steam (10 bar)
Annual fuel costs: 22 M€
Impact of a 10% gas price increase ...
loss of annual
contribution margin
M € /a
w/o emissions trading
with EU Emissions Trading Scheme
3
3
2
2
1
1
CHP
reference
CHP
reference
CCPP w.
steam extraction
grid + gas boiler
CCPP w.
steam extraction
grid + gas boiler
Fig. 1: With the EU Emissions Trading Scheme in place a natural gas price increase will
hardly reduce the contribution margin of a CHP plant.
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The EU Emissions Trading Scheme introduced CO2 as a new commodity. The scope of
this paper is to demonstrate that, contrary to the common perception, this new commodity
is leading to a reduced risk for CHP plants.
gas price
heat demand
CO2 price
regulation:
in feed tariffs ...
power price
allocation of
CO2 allowances
Fig. 2: External factors influencing the economic performance of a CHP plant. The EU
ETS has introduced two new factors: CO2 allocation and CO2 price
Allocation to new entrant CHP and Power Plants
(gas-fired, high efficiency)
in allowances per tonne of CO2 emitted
1.8
1.6
CHP
Sources: Vattenfall and
preliminary results of a
COGEN Europe survey
Power Plant
1.4
1.2
1
0.8
0.6
0.4
0.2
0
Germany
Sweden
UK
Lithuania
Fig. 3: Allocation of CO2 allowances varies considerably across different EU member
states
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The allocation effect is centered around the question: ”how many allowances does a plant
get for free?”. This has been very much in the focus of the 2004 ”allocation battle” in the
policy-making and lobbying arena. Indeed there are considerable differences in the
allocation of EU Allowances (EUA) to new entrant plants. Although the allocation process
in the EU is amazingly lacking in transparency, there are first studies comparing new
entrant allocation in different member states (Fig 3.). In many member states the
environmental benefits of CHP are rewarded by a somewhat better allocation compared to
plain power generation. This allocation effect can change the annual power revenues by as
much as 2% to 5%.
gas price
heat demand
?
CO2 price
?
?
regulation:
in feed tariffs ...
power price
allocation of
CO2 allowances
Fig. 4: The new commodity CO2 is not independent from gas and power price
The economic impact of revenues or costs for EU Allowances is understood as the direct
impact of the EU ETS. There is, however, no doubt, that the EU ETS has considerable
indirect impacts. This is due to the fact that gas, CO2 and power prices are fundamentally
linked (Fig.4.). As these links are not so obvious at first glance, they are often overlooked.
This paper will also demonstrate that the indirect impact of the EU ETS on the profitability
of CHP can exceed the direct impact.
The impact of gas price changes on power price is not at all new. In plain theory there
should be a full pass-through of gas price increases, when a gas fired plant is at the margin
(=defines the market closing price), while there should be no pass-through in times where a
coal plant is at the margin. Of course there are some practical constraints like contractual
structure (take or pay contracts) or plant dispatchability. The average share of time, where
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gas plants are at the margin, will vary markedly from country to country (Fig.5. left hand
side). Although power markets are linked to some extent in the EU, the pass-through of a
gas price increase to the power market should be analyzed country by country. In this case
the example of Germany is taken for the further model calculation. Gas plants are
determining market prices 20% of the time. Hence it is simply assumed that only 20% of
the increase of the short-term marginal costs of a gas plant will be observed in the average
power price (Fig.5. right hand side).
assumption: share
of hours with gas
plants at the margin
€/MWh power price inc.
per €/MWh gas price inc.
Austria
0%
0,00
Spain
4%
0,08
Germany
20%
0,60
Denmark
30%
0,79
UK
40%
0,85
Practical constraints:
• take or pay contracts
• constraints in plant dispatch ability
• links between European power markets
4
€/MWhel
power price adder from gas
Plain theory:
• 100% pass through of gas price increase to power
prices, if the marginal plant is a gas plant
• 0% pass through, if the marginal plant is a coal plant
model
assumption
2
0
0
2
4
6
gas price increase €/MWh
Fig. 5: Link between natural gas and power price – a very simplified approach
How is the price of CO2 allowances linked to gas price changes? To understand this link,
one has to consider CO2 reduction options and the EU-wide marginal abatement cost
curve. One of the largest reversible short-term options to reduce CO2 is the redispatch
from coal plants to existing gas plants. Most of the other abatement options require
investment and hence are neither short term nor reversible. The basis for the economics of
this redispatch is the fact that CO2 costs will have to be added to the short-term marginal
costs of a plant. As this CO2 cost adder is bigger for coal plants than for gas plants, at a
certain break-even price of CO2 a coal plant with relatively high short-term marginal costs
will be pushed out of the merit order and a gas plant will be included instead. This
switching price is very plant-specific. Based on a market model of the EU power plant fleet
one can determine a ranking of these switching opportunities in terms of the break-even
CO2 price. Thus an EU-wide marginal abatement cost curve (for redispatch only – other
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options are not included here) can be determined. (Fig.6. left hand side). If, for example,
EU-wide 40 Mt CO2/a has to be reduced, one could determine the resulting CO2 price, if
all of this reduction has to be achieved in the short-term by redispatch. With a higher gas
price and a stable coal price a higher CO2 price will be necessary to compensate the
difference in short-term marginal costs of a coal and a gas plant. Thus the marginal
abatement cost curve will be strongly dependent on the gas/coal price ratio. The sensitivity
is remarkably strong. To observe this fundamental effect from current EUA prices, it is
necessary to separate it from various other effects like weather, amount of available
hydropower, market inefficiencies - particularly in this early phase of the market -, impact
of political allocation decisions and, in a later stage, the discontinuity at the end of 2007,
where EUAs cannot be banked. However, there is strong consensus, that this fundamental
link does exist and is implemented in various market models. For the sample model
calculation in this case a simplified own model is used, based on a simplified country-bycountry assessment (Fig.6 right hand side).
20
20
Gas: € 4,57 /GJ
Coal: $ 60/t
15
10
Gas: € 3,77 /GJ
Coal: $ 55/t
05
Source: Climate Change Capital – 07.12.2004
Strategic Consequences for Corporates
HypoVereinsbank
0
0
20
40
60
80
100
Reduction potential through redispatch [Mt CO2/a]
€/t CO2
break even CO2 price
to switch from coal to gas
break even CO2 price
to switch from coal to gas
€/t CO2
Source: Siemens PG internal model
15
break even price
for redispatch from
coal to gas in EU25
to reduce 40 Mt CO2
per year
10
05
0
1,4
1,6
1,8
2,0
Gas/Coal price ratio
Fig. 6: Link between Natural Gas price and CO2 price – demonstrating the fundamental
principle
There has been an intensive debate about the question as to how much of the value of EU
Allowances will be passed into power markets. Based on plain theory in deregulated
markets, 100% of the value of allowances required to produce one MWh power will have
to be included in the short-term marginal costs of a plant. Hence a plant at the margin
should increase the market closing price by 100% of the value of its required CO2
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allowances (see Fig.7. grey field). This looks puzzling at a first glance, as only 1-10% of
these allowances really have to be purchased. The remaining 90-99% can be understood as
opportunity cost – in case of a no bid decision these allowances could be sold to the
emissions market, irrespective of whether they are obtained free or were purchased. So the
pass-through of opportunity costs is simply system-immanent. This fact has been discussed
in many studies and has been subject to an intense debate between policy makers, powerintensive industry and utilities.
In practice there will be some constraints to this pass-through of opportunity costs:
different levels of competition and dispatch constraints. Thus, for our model calculation we
will assume that only about 50% of the opportunity costs will be passed through (Fig.7. red
line). In terms of the introduced hypothesis that CHP will turn out to be a great hedge
across gas-, CO2- and power prices, this is a conservative approach.
Practical constraints:
• increase of short term marginal costs is not
necessarily same as increase of price
• constraints in dispatch ability
• depends on intensity of competition
10
Sources: DRKW 2003, ILEX Energy
Consulting July 2004,Siemens PG
internal model
th
10 eor
0% y:
pa
ss
t
hr
ou
gh
€/MWhel
power price adder from CO2
Plain theory (for liberalized markets):
• 100% pass through of value of CO2
allowances from the marginal plant
although only 1%-10% really have to be
purchased.
• Depends, whether gas or coal is at the
margin
05
model
assumption
0
0
5
10
CO2 price €/t
Fig. 7: Link between CO2 price and power price
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15
gas price
20
Source: Siemens PG internal model
break even CO2 price
to switch from coal to gas
€/t CO2
break even price
for redispatch from
coal to gas in EU25
to reduce 40 Mt CO2
per year
15
10
05
4
1,4
1,6
1,8
2,0
Gas/Coal price ratio
05
th
ro
model
assumption
2
0
0
2
4
6
gas price increase €/MWh
th
10 eor
0% y:
pa
ss
power price adder from CO2
10
Sources: DRKW
€/MWhel 2003, ILEX Energy
Consulting July
2004,Siemens PG
internal model
ug
h
CO2 price
power price adder from gas
€/MWhel
0
model
assumption
0
0
5
10
CO2 price €/t
15
power price
Fig. 8: Very simplified model to study sensitivities of CHP economics
Fig.8. shows the very rudimentary model of linked gas, CO2 and power markets, which is
used for the further case studies. The approach of the case studies is to determine only the
change of contribution margins, not the absolute economic performance of the CHP plants
considered. This is necessary, as the absolute performance will always be highly casespecific with lots of local boundary conditions. The changes of the annual contribution
margin of a CHP plant will consist of the following components:
• Additional costs for gas
• Additional revenues from CO2 allowances (as the value of the excess allowances
increases)
• Additional value of the produced power (as the power market price is taken as a
reference)
The reference case (purchase power from the grid and produce the heat with a gas-fired
boiler) will see changes in the contribution margin due to
• Additional fuel costs for the boiler
• Additional power costs
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Only differences, not absolute values:
• In CHP economic assessments are always very case specific
• Only changes of the annual contribution margin are assessed
Example:
10% gas price increase -> 48% CO2 price increase -> 4 % power price increase
reference-case
CHP-case
1
resulting loss of
contribution margin
2
additional fuel costs
(boiler)
additional
power reven.
1
additional CO2
revenues
2
resulting loss of
contribution margin
3
additional fuel
costs (CHP)
loss of annual
contribution margin
M € /a
3
additional
power costs
grid + gas boiler
122 MW CCPP with steam extraction
Fig. 9: How the loss of contribution margin is determined – based on data from Fig.18
and Fig.19
It should be noted that, in this comparison, the boundaries of the calculation are the power
and heat production of the plant, not the power and heat demand on the site. Although this
is quite unconventional, the approach is taken to focus the further calculation on the
considered hedging effect.
The examples considered might be typical for a wide range of CHP applications.
(Examples will be described under headings below.)
Type of plant gas fired CHP
typical application
Electrical capacity
Heat capacity
Fuel capacity
Full load operation
Average power load factor
Average heat load factor
Fuel consumption
Power production
Useable heat production
Electrical efficiency
Thermal efficiency
Total efficiency
MW
MW
MW
h/a
%
%
MWh/a
MWh/a
MWh/a
%
%
%
Case 1
CCGT with
backpressure
Steam Turbine
Case 2
CCGT with
extraction condensing
Steam Turbine
(process steam 10 bar)
Case 3
Simple Cycle
Gas Turbine
Utility, District Heating
and Power Generation
19
21
45,5
8.000
100%
100%
364.000
152.000
168.000
42%
46%
88%
Industry, Chemicals
Industry, Paper
Fig. 10: Typical CHP cases and assumed performance data
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122
75
242,0
8.000
100%
90%
1.936.000
976.000
540.000
50%
28%
78%
5
8
16,0
8.000
100%
100%
128.000
40.000
64.000
31%
50%
81%
Siemens Power Generation Industrial Applications is currently modernizing a coal and
gas- fired plant for the Utility ESTW Erlangen, Germany, that will provide power and heat
to the city district system. Siemens is delivering a 13 MW SGT-400 gas turbine, a fired
heat recovery steam generator and a 11 MW steam turbine SST-300. The peak electrical
and thermal output will be more than 20 MW each. The plant is scheduled to begin
commercial operation in October 2005.
Fig. 11: CHP case ”Utility district heating” ESTW Erlangen in Germany
Sappi Europe Limited, is located at the Sappi paper mill in Blackburn, Lancashire with the
primary objective of meeting the paper mill’s power and process steam requirements, and
exporting the power generated into the grid. The plant has been equipped with the 45 MW
SGT-100 and a 19 MW intermediate pressure steam turbine as a combined cycle power
plant (SCC-800), supplying process steam and up to 60 MW electrical power. The heat
recovery steam generator is a two pressure boiler delivering high pressure steam to the
steam turbine and low pressure steam to the paper mill. The total steam production is
40tons/hr.
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Fig. 12: CHP case ”Industrial steam supply”, Blackburn Paper Mill in UK
Under contract to Essent Belgium, Siemens PG is building a combined heat and power
plant as a turnkey project in Antwerp. The plant will comprise two 45 MW SGT-800 gas
turbines. The new 120-MW gas-fired plant (SCC-800) will supply electricity and 220
metric tons of steam to the Ineos Petrochemical complex. The plant is scheduled to begin
commercial operation in early 2006.
Fig. 13: CHP case ”Petrochemical Industry”, INESCO, Belgium
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In Fig.14 the allowance allocation situation for Germany is taken as an example. For new
entrant CHP, Germany has a double benchmark approach, applied to planned production.
In this case a 365 g/kWhel power benchmark is assumed. It might turn out that smaller gas
plants can even apply for slightly higher benchmarks. The benchmark for heat depends on
the supplied temperature level: hot water or steam. As already indicated in Fig.3, a slight
over-allocation for CHP is the result, rewarding the well-known efficiency benefits.
Economic base data are shown in Fig.15.
Case 1
CCGT / back
pressure ST
CO2 allocation - example Germany
Assumed power benchmark for CO2 allocation
allocation for power production
Assumed heat benchmark for CO2 allocation
allocation for heat production
total allocation
excess allowances
kg/kWh el
t/a
kg/kWh el
t/a
t/a
t/a
365
55480
215
36120
91600
18.800
Case 2
CCGT /
extraction ST
Case 3
Simple cycle GT
365
356240
225
121500
477740
90.540
365
14600
215
13760
28360
2.760
Fig. 14: Assumed allocation of CO2 allowances – example Germany with double
benchmark
Case 1
CCGT / back
pressure ST
Economic base data: CHP
Power price
Gas Price
Coal price
Gas/coal ratio
CO2 price
annual revenue from power
annual revenue from CO2 overallocation
CO2 revenue rel. to power revenue
annual fuel costs
Economic base data: reference case (grid + boiler)
power costs
fuel costs
Case 2
CCGT /
extraction ST
Case 3
Simple cycle GT
€/MWh
€/GJ
€/GJ
€/t
€/a
€/a
%
€/a
42,00
3,10
1,72
1,80
9,06
6.384.000
170.334
2,67%
4.062.240
42,00
3,10
1,72
1,80
9,06
40.992.000
820.323
2,00%
21.605.760
42,00
3,10
1,72
1,80
9,06
1.680.000
25.007
1,49%
1.428.480
€/a
€/a
6.384.000
2.083.200
40.992.000
6.696.000
1.680.000
793.600
Fig. 15: Economic boundary conditions and reference assumptions for both scenarios:
CHP and reference (power from the grid and heat from gas-fired boiler)
To better understand the system, a first sensitivity calculation considers an ”external”
change of the CO2 price (Fig. 16 and Fig.17). This external change might be a reduced
import of allowances from project-based mechanisms from outside the EU, a cold winter
with increased demand for space heating, a dry year with lower hydropower production or
a hot summer with increased cooling demand. Due to the pass-through of opportunity costs
(see Fig.7) the power price effect is already bigger than the direct impact of the CO2
allowances. The changes in the scenario without emissions trading are, of course, zero (red
line in Fig. 17).
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Case 1
CCGT / back
pressure ST
EU ETS CHP case
additional revenue from power
additional revenue from CO2
additional fuel costs
net loss of contribution margin
EU ETS reference case
additional power costs
additional fuel costs (boiler gas)
net loss of contribution margin
Case 2
CCGT /
extraction ST
Case 3
Simple cycle GT
€/a
€/a
€/a
€/a
172.146,41
85.167,17
(257.313,58)
1.105.361,14
410.161,47
(1.515.522,61)
45.301,69
12.503,27
(57.804,95)
€/a
€/a
€/a
172.146,41
172.146,41
1.105.361,14
1.105.361,14
45.301,69
45.301,69
Fig. 16: Change of contribution margin due to a 50% CO2 price increase – considered only
for the EU Emissions Trading Scheme (obviously not applicable for a scenario without
emissions trading)
reference
grid + boiler
1,0
0,5
w/o Emissions trading
(0,5)
reference grid+boiler
with Emissions trading
CHP
increase of annual
contribution margin
M € /a
loss of annual
contribution margin
M € /a
Example: 50% CO2 price increase -> 2,7 % power price increase
1,5
(1,0)
CHP
with Emissions trading
(1,5)
case 1:
CCGT /
back pressure ST
case 2:
CCGT /
extraction ST
case 3:
Simple cycle GT
Fig. 17: Change of contribution margin caused by an ”external” 50% increase of the CO2
price
The CHP benefit in this scenario is mainly based on the fact that the operator can benefit
from the pass-through of CO2 opportunity costs to the power market and in addition can
sell excess allowances at a higher price.
An even more impressive case is the sensitivity of the contribution margin to a 10% gas
price increase (stable coal price assumed). Fig.18 shows the sensitivities if no emissions
trading is in place (red lines in Fig.20). Fig.19 shows the same sensitivities with the EU
ETS. Increased fuel costs are now almost compensated by the higher revenues from power
and CO2. In relative terms this effect is not so strong in case 3 (Gas Turbine (GT) Simple
Cycle) and strongest in case 2 (Gas Turbine Combined Cycle (CCGT) with extraction
steam turbine (ST).
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Case 1
CCGT / back
pressure ST
CHP (no Emissions Trading)
additional revenue from power
additional fuel costs
net additional costs
Reference case (no Emissions Trading)
additional power costs
additional fuel costs (boiler gas)
net additional costs
Case 2
CCGT /
extraction ST
Case 3
Simple cycle GT
€/a
€/a
€/a
101.779,20
406.224,00
304.444,80
653.529,60
2.160.576,00
1.507.046,40
26.784,00
142.848,00
116.064,00
€/a
€/a
€/a
101.779,20
208.320,00
310.099,20
653.529,60
669.600,00
1.323.129,60
26.784,00
79.360,00
106.144,00
Fig. 18: Change of contribution margin due to a 10% natural gas price increase – scenario
without emissions trading
Case 1
CCGT / back
pressure ST
EU ETS CHP case
additional revenue from power
additional revenue from CO2
additional fuel costs
net loss of contribution margin
EU ETS reference case
additional power costs
additional fuel costs (boiler gas)
net loss of contribution margin
Case 2
CCGT /
extraction ST
Case 3
Simple cycle GT
€/a
€/a
€/a
€/a
265.925,28
81.209,11
406.224,00
59.089,60
1.707.520,23
391.099,64
2.160.576,00
61.956,13
69.980,34
11.922,19
142.848,00
60.945,47
€/a
€/a
€/a
265.925,28
208.320,00
474.245,28
1.707.520,23
669.600,00
2.377.120,23
69.980,34
79.360,00
149.340,34
Fig. 19: Change of contribution margin due to a 10% natural gas price increase – scenario
with EU Emissions Trading Scheme
In Fig.20 it can clearly be seen that the CHP option is a kind of physical hedge across the
commodities gas, CO2 and power. The contribution margin of CHP in the EU ETS
environment is much less sensitive to a gas price change than either CHP without
emissions trading (red line) or the reference case with emissions trading (grey bar).
2,5
2,0
w/o Emissions trading
1,5
reference grid+boiler
with Emissions trading
1,0
CHP
with Emissions trading
CHP
0,5
case 1:
CCGT /
back pressure ST
reference
grid + boiler
loss of annual
contribution margin
M € /a
Example:
10% gas price increase -> 48% CO2 price increase -> 4 % power price increase
case 2:
CCGT /
extraction ST
case 3:
Simple cycle GT
Fig. 20: Change of contribution margin due to a 10% natural gas price increase
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Summary and conclusions
The new commodity CO2 brings some unexpected changes. Beyond the direct impact of
allocation one should have a closer look at the indirect impacts of the new links:
gas price -> CO2 price -> power price
In the EU ETS CHP will be much less sensitive to gas price changes and can be regarded as a
physical cross-commodity hedge
Of course investments in CHP will primarily have to be based on absolute profitability, which
is highly case-specific. However, the reduced risk should have a clear value in investment
planning.
Sources:
To be added
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