Price equilibria in spot and reserve markets and the
role of new players like CHP
Christian Furtwängler*, Julia Bellenbaum, Christoph Weber
House of Energy Markets and Finance
Vienna, April 27, 2017
Agenda
Marketing Flexibilities of a Simplified CHP Portfolio
Flexibility and its price
1
Reserve bids and spot prices – defining equilibria
2
Opportunity costs of reserve provision in CHP portfolios
3
Conclusions
4
4/27/2017
Agenda
Marketing Flexibilities of a Simplified CHP Portfolio
Flexibility and its price
1
Reserve bids and spot prices – defining equilibria
2
Opportunity costs of reserve provision in CHP portfolios
3
Conclusions
4
4/27/2017
What is flexibility (in this approach)?
Flexibility and its price
 Flexibility denotes – roughly – “the ability to modify generation and/or consumption patterns to
provide a service within the energy system” (definition by OFGEM)
 i.e. frequency regulation, reserve provision, load shedding, etc.
 In Central Europe, this flexibility is procured by auctions for primary, secondary and tertiary reserve
 So far, flexibility is mostly provided by conventional power plants
 Focus on these generating facilities by most studies about reserve markets
 Positive reserve energy is provided by ramping these plants up
 Negative reserve energy is provided by ramping these plants down
 However, there are new players entering the reserve market
 More on that later
4/27/2017
What would we expect?
Flexibility and its price
2016 Average Deviation of Actual and DA-Forecast by the TSOs (Wind + Solar)
100
50
0
-50
-100
-150
00:00:00
00:30:00
01:00:00
01:30:00
02:00:00
02:30:00
03:00:00
03:30:00
04:00:00
04:30:00
05:00:00
05:30:00
06:00:00
06:30:00
07:00:00
07:30:00
08:00:00
08:30:00
09:00:00
09:30:00
10:00:00
10:30:00
11:00:00
11:30:00
12:00:00
12:30:00
13:00:00
13:30:00
14:00:00
14:30:00
15:00:00
15:30:00
16:00:00
16:30:00
17:00:00
17:30:00
18:00:00
18:30:00
19:00:00
19:30:00
20:00:00
20:30:00
21:00:00
21:30:00
22:00:00
22:30:00
23:00:00
23:30:00
Actual – Forecast [MW]
150
Data Source:
Netztransparenz.de
and own calculations
 Residual load uncertainty due to intermittent energy supply from renewable sources challenges the
electricity system
 More flexibility is needed to balance short-term imbalances
 With a higher installed capacity from RES, the gravity of this effect is rising and more flexible capacities are
needed
 Conclusion: more demand for flexibility should result in higher reserve prices and higher incentives to
increase flexibility
27.04.2017
PRL
PRL GER
SRL NEG_HT
27.04.2017
SRL NEG_NT
SRL POS_HT
30.11.2016
31.10.2016
30.09.2016
31.08.2016
31.07.2016
30.06.2016
31.05.2016
30.04.2016
31.03.2016
29.02.2016
31.01.2016
31.12.2015
30.11.2015
31.10.2015
30.09.2015
31.08.2015
31.07.2015
30.06.2015
31.05.2015
30.04.2015
31.03.2015
28.02.2015
31.01.2015
31.12.2014
30.11.2014
31.10.2014
30.09.2014
31.08.2014
31.07.2014
30.06.2014
31.05.2014
30.04.2014
31.03.2014
28.02.2014
31.01.2014
31.12.2013
30.11.2013
31.10.2013
30.09.2013
31.08.2013
31.07.2013
30.06.2013
31.05.2013
30.04.2013
31.03.2013
28.02.2013
31.01.2013
31.12.2012
Reserve amount [MW]
Rising load uncertainty → Rising demand for flexibility? (1)
Flexibility and its price
Auction Amounts Primary and Secondary Reserve GER
2013-2016
3.000
2.500
2.000
1.500
1.000
500
0
SRL POS_NT
Data Source:
Regelleistung.net
Weighted average
Median
Lowest bid
27.04.2017
Highest allocated bid
# bids
30.11.2016
31.10.2016
30.09.2016
31.08.2016
31.07.2016
30.06.2016
31.05.2016
30.04.2016
31.03.2016
29.02.2016
31.01.2016
31.12.2015
30.11.2015
31.10.2015
30.09.2015
31.08.2015
31.07.2015
30.06.2015
31.05.2015
30.04.2015
31.03.2015
28.02.2015
31.01.2015
31.12.2014
30.11.2014
31.10.2014
30.09.2014
31.08.2014
31.07.2014
30.06.2014
31.05.2014
30.04.2014
31.03.2014
28.02.2014
31.01.2014
31.12.2013
30.11.2013
31.10.2013
30.09.2013
31.08.2013
31.07.2013
30.06.2013
31.05.2013
30.04.2013
31.03.2013
28.02.2013
31.01.2013
31.12.2012
Reserve Provision Prices [€/MW]
10.000
8.000
6.000
150
5.000
4.000
100
2.000
0
No. of Allocated Bids
The observed value of flexibility – primary reserve prices
2013-2016
Flexibility and its price
250
9.000
R² = 0,8533
200
7.000
3.000
50
1.000
0
Linear (# bids)
Data Source:
Regelleistung.net
And own calculations
Median peak
Median off-peak
27.04.2017
# bids peak
# bids off-peak
3.000
200
2.000
150
100
1.000
50
0
0
Higher peaks and lower valleys
for negative reserve provision
250
3.000
200
2.000
150
100
1.000
50
0
0
Number of allocated bids
4.000
Number of allocated bids
30.11.2016
31.10.2016
30.09.2016
31.08.2016
31.07.2016
30.06.2016
31.05.2016
30.04.2016
31.03.2016
29.02.2016
31.01.2016
31.12.2015
4.000
30.11.2015
Negative Secondary Reserve Price Development 2013-2016 [€/MW]
31.10.2015
30.09.2015
# bids peak
31.08.2015
31.07.2015
30.06.2015
31.05.2015
30.04.2015
Median off-peak
31.03.2015
28.02.2015
31.01.2015
31.12.2014
30.11.2014
31.10.2014
30.09.2014
Median peak
31.08.2014
31.07.2014
30.06.2014
31.05.2014
30.04.2014
31.03.2014
28.02.2014
31.01.2014
31.12.2013
30.11.2013
31.10.2013
30.09.2013
31.08.2013
31.07.2013
30.06.2013
31.05.2013
30.04.2013
31.03.2013
28.02.2013
31.01.2013
31.12.2012
The observed value of flexibility – secondary reserve
provision prices 2013-2016
Flexibility and its price
Positive Secondary Reserve Price Development 2013-2016 [€/MW]
250
# bids off-peak
Data Source:
Regelleistung.net
And own calculations
Rising load uncertainty → Rising demand for flexibility? (2)
Flexibility and its price
Calls of secondary reserve [Monthly average % of total procured MW]
25%
20%
15%
10%
5%
0%
percentage neg
27.04.2017
percentage pos
Data Source:
Regelleistung.net
And own calculations
The observed value of flexibility – secondary reserve energy
prices
Flexibility and its price
Positive Secondary Reserve Energy Price (Weekly median) [€/MWh]
100
80
60
40
20
0
Median pos peak
Median pos off-peak
Negative Secondary Reserve Energy Price (Weekly median) [€/MWh]
60
30
0
-30
Median neg peak
Median neg off-peak
27.04.2017
Data Source:
Regelleistung.net
And own calculations
What has changed since 2014?
Flexibility and its price
 New market boundaries for primary reserve
 The Netherlands, Austria, Belgium and France entered the joint auction of Germany and Switzerland
 Increasing coordination of TSO efforts
 New products and changes of design in the spot market
 Day-ahead auction since December 2014; gate closure now 30 minutes ahead of delivery
 Growing intraday trading volumes
 More opportunities to counter forecast deviations ahead of the balance markets
 New players in the reserve market
 More and smaller generating units in the market (enabled by pooling), DSM
 Flexibility demand growth < Flexibility supply growth?
27.04.2017
peak pos
off-peak pos
27.04.2017
peak neg
30.11.2016
31.10.2016
30.09.2016
31.08.2016
31.07.2016
30.06.2016
31.05.2016
30.04.2016
31.03.2016
29.02.2016
31.01.2016
31.12.2015
30.11.2015
31.10.2015
30.09.2015
31.08.2015
31.07.2015
30.06.2015
31.05.2015
30.04.2015
31.03.2015
28.02.2015
31.01.2015
31.12.2014
30.11.2014
31.10.2014
30.09.2014
31.08.2014
31.07.2014
30.06.2014
31.05.2014
30.04.2014
31.03.2014
28.02.2014
31.01.2014
31.12.2013
30.11.2013
31.10.2013
30.09.2013
31.08.2013
31.07.2013
30.06.2013
31.05.2013
30.04.2013
31.03.2013
28.02.2013
31.01.2013
31.12.2012
Average allocated bid size [MW]
Average allocated bid sizes for secondary reserve 20132016
Flexibility and its price
MW per bid
45
40
35
30
25
20
15
10
5
0
off-peak neg
Data Source:
Regelleistung.net
And own calculations
Agenda
Marketing Flexibilities of a Simplified CHP Portfolio
Flexibility and its price
1
Reserve bids and spot prices – defining equilibria
2
Opportunity costs of reserve provision in CHP portfolios
3
Conclusions
4
4/27/2017
Basics: Reserve power bands – the case of primary reserve
(one conventional unit)
Reserve bids and spot prices – defining equilibria
P
𝑷𝒎𝒂𝒙
Optimal operation point
No reserve marketed With reserve marketed
X
Spot Revenue Losses
If 𝒑𝑺𝒑𝒐𝒕 ≥ 𝑴𝑪
X
𝑷𝒎𝒂𝒙 − 𝑷𝒓𝒆𝒔𝒆𝒓𝒗𝒆
= 𝑷𝒓𝒆𝒔𝒆𝒓𝒗𝒆 ∗
෍
𝕀 𝒑𝑺𝒑𝒐𝒕 ≥𝑴𝑪 𝒕 ∗ (𝒑𝑺𝒑𝒐𝒕 − 𝑴𝑪)
𝒕∈𝑻𝒓𝒆𝒔𝒆𝒓𝒗𝒆
With:
X
𝑷𝒎𝒊𝒏 + 𝑷𝒓𝒆𝒔𝒆𝒓𝒗𝒆
𝑷𝒎𝒊𝒏
𝑻𝒓𝒆𝒔𝒆𝒓𝒗𝒆 = {𝒕𝟏 , … , 𝒕𝟏𝟔𝟖 }
“Must-run” Losses
(X)
If 𝒑𝑺𝒑𝒐𝒕 ≤ 𝑴𝑪
= (𝑷𝒎𝒊𝒏 + 𝑷𝒓𝒆𝒔𝒆𝒓𝒗𝒆 ) ∗
෍
𝕀 𝒑𝑺𝒑𝒐𝒕 ≤𝑴𝑪 𝒕 ∗ (𝑴𝑪 − 𝒑𝑺𝒑𝒐𝒕 )
𝒕∈𝑻𝒓𝒆𝒔𝒆𝒓𝒗𝒆
0
X
With:
𝑻𝒓𝒆𝒔𝒆𝒓𝒗𝒆 = {𝒕𝟏 , … , 𝒕𝟏𝟔𝟖 }
 The resulting sum of these (opportunity) costs of reserve provision
accumulated over the reserve period divided by 𝑷𝑹𝒆𝒔𝒆𝒓𝒗𝒆 represents
the minimum reserve bid of this unit
27.04.2017
Minimum bids for one-sided reserve provision of
conventional power plants– theoretical results
Reserve bids and spot prices – defining equilibria
Negative Reserve
Efficient Reserve
Provision Price
(≥) [€/MW]
෍
𝕀 𝑝𝑆𝑝𝑜𝑡 ≤𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑀𝐶𝑒𝑙 − 𝑝𝑆𝑝𝑜𝑡,𝑡
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
Positive Reserve
𝑃𝑚𝑖𝑛 + 𝑃𝑅𝑒𝑠𝑒𝑟𝑣𝑒
∗
𝑃𝑅𝑒𝑠𝑒𝑟𝑣𝑒
𝕀 𝑝𝑆𝑝𝑜𝑡 ≤𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑀𝐶𝑒𝑙 − 𝑝𝑆𝑝𝑜𝑡,𝑡 ∗
෍
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
෍
𝑃𝑚𝑖𝑛
𝑃𝑅𝑒𝑠𝑒𝑟𝑣𝑒
𝕀 𝑝𝑆𝑝𝑜𝑡 ≥𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑝𝑆𝑝𝑜𝑡,𝑡 − 𝑀𝐶𝑒𝑙
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
Efficient Reserve
Energy Price (≥)
[€/MWh]
−𝐸𝑡 𝑀𝐶𝑒𝑙
𝐸𝑡 𝑀𝐶𝑒𝑙
 Opportunity costs of negative energy provision only if spot prices are below marginal costs
 must-run cost
 Opportunity costs of negative energy provision are 0, if spot prices are above marginal costs!
 Steepness of Merit-Order drives reserve price levels!
 What happens, if a plant doesn’t have a minimum capacity (e.g. wind, solar, RoR)?
27.04.2017
+
From individual behaviour to the system equilibrium
Reserve bids and spot prices – defining equilibria
 Every market participant with an eligible unit calculates his/her expected cost for reserve
provision during the respective period as a bid floor
 Bid sizes per participant depend on plant characteristics (i.e. ramping capability per time)
 However, the bids need to be integer values ≥ 1
 It is possible to sort all provision costs in a corresponding reserve bid curve (“reserve power meritReserve Bid
order”):
[€/MW]
 The resulting price represents the cost of
flexibility for a given reserve period
 There is arbitrage between spot and reserve
marketing in expectation
 (Timeframe-dependent) System Equilibrium
Bid n+1
Highest allocated bid price
Bid n
Consumer rent
Costs
 Producer rent = 0
Bid 1
Reserve power need of TSO [MW]
(Common information)
27.04.2017
Reserve Power [MW]
The effect of provision timeframes
Reserve bids and spot prices – defining equilibria
 2 cost-amplifying reasons of longer reserve timeframes:
1. Longer timeframes should – obviously – result in higher total provision costs per period
 Longer period means more “Must-run” and/or “Spot revenue” losses
2. This effect, however, is not “additive”, but “super-additive”!
 Shorter timeframes (~4 hours) can be expected to often have homogeneous spot price levels
 Plants with marginal costs near to this particular four hour level have very little costs of reserve provision
 Longer timeframes (peak/off-peak = 60 hours/108 hours) cannot be expected to have such homogeneous
price levels!
 Plants with marginal costs near the average peak/off-peak spot prices have the lowest cost of reserve provision, but
will experience more price deviations during these timeframes
 Total weekly provision costs of all “optimal 4 hour reserves” (42 products pos/42 products neg)
≤ total weekly provision costs of “optimal peak/off-peak reserves” (2 products pos/ 2 products neg)
27.04.2017
Example: Week 03, January 2014, with minimum capacity
Reserve bids and spot prices – defining equilibria
Reserve cost minimizing MC – 4 hourly product
Assumption: 𝑷𝒎𝒊𝒏 = 𝟏𝟎 𝑴𝑾, 𝑷𝒓𝒆𝒔𝒆𝒓𝒗𝒆 = 𝟏𝟎 𝑴𝑾
Spot Price [€/MWh]
80
Optimal provision cost:
5793 € for 42 positive products
0 € for 42 negative products
70
60
50
40
30
20
10
0
SpotPrice
MC ideal neg
MC ideal pos
Reserve cost minimizing MC –peak/off-peak product
Spot Price [€/MWh]
80
Optimal provision cost:
10520 € for 2 positive products
0 € for 2 negative products
70
60
50
40
30
20
10
0
SpotPrice
MC ideal neg
27.04.2017
MC ideal pos
Minimum bids for one-sided reserve provision of nonconventional power plants– theoretical results
Reserve bids and spot prices – defining equilibria
Negative Reserve
Efficient Reserve
Provision Price
(≥) [€/MW]
Efficient Reserve
Energy Price (≥)
[€/MWh]
෍
Positive Reserve
𝕀 𝑝𝑆𝑝𝑜𝑡 ≤𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑀𝐶𝑒𝑙 − 𝑝𝑆𝑝𝑜𝑡,𝑡
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
෍
𝕀 𝑝𝑆𝑝𝑜𝑡 ≥𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑝𝑆𝑝𝑜𝑡,𝑡 − 𝑀𝐶𝑒𝑙
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
−𝐸𝑡 𝑀𝐶𝑒𝑙
𝐸𝑡 𝑀𝐶𝑒𝑙
 Note: 𝑀𝐶𝑒𝑙 ≈ 0 for Wind, Solar and RoR
 For negative reserve, the minimum power band to be withheld at all times is just 𝑃𝑅𝑒𝑠𝑒𝑟𝑣𝑒
 The opportunity costs are in this case merely driven by the price spread of this technology
 No opportunity costs for negative reserve, if there is no need for back-up to cope with quantity risk
 No opportunity costs for positive reserve at spot prices below or equal to zero, if… (cf. above)
 Short time horizons for provision facilitate provision of reserves by intermittent renewables
27.04.2017
Strategic interaction between reserve power and reserve
energy prices
Reserve bids and spot prices – defining equilibria
 Apparently, historically observed reserve energy prices don’t correspond to the assumption of a
reserve energy bid mirroring marginal costs
 Higher activated bids have been observed
 Reserve energy bids only decide on activation order, not on bid allocation
′
 Optimization problem: max𝑝𝐸𝑛𝑒𝑟𝑔𝑦 𝑝𝐸𝑛𝑒𝑟𝑔𝑦 − 𝑀𝐶 ∗ 𝑝𝑟𝑜𝑏𝑎𝑐𝑡 𝑝𝑒𝑛𝑒𝑟𝑔𝑦 ) with 𝑝𝑟𝑜𝑏𝑎𝑐𝑡
𝑝𝑒𝑛𝑒𝑟𝑔𝑦 < 0
 Assuming that all provision costs are covered by the provision price, an energy bid higher than marginal
costs results in a positive expected profit
 If bidder is risk-loving, it is also possible to lower his or her reserve provision bid below his or
her opportunity costs, rising the acceptance probability of the bid and still have a positive
expected return
 As a result, there is an array of possible bidding strategies
27.04.2017
Agenda
Marketing Flexibilities of a Simplified CHP Portfolio
Flexibility and its price
1
Reserve bids and spot prices – defining equilibria
2
Opportunity costs of reserve provision in CHP portfolios
3
Conclusions
4
4/27/2017
CHP – a flexible technology?
Opportunity costs of reserve provision in CHP portfolios
 CHP plants are often considered very efficient, but not very flexible
 Heat demand to be satisfied, often heat led operation of CHP plants
 Thus, “hard” restrictions imposed on plant operation and limitation of flexibility
 The vast majority of installed CHP units is not eligible for individual participation in reserve markets
 Minimum bid of 1 MW for primary reserve, 5 MW for secondary and tertiary reserve
 However, a joint bid of a plant pool is possible
 The flexibility of CHP plants further varies with the degrees of freedom of operation
 Ratio of electricity and heat production might be fixed (1 degree of freedom), further limiting flexibility
27.04.2017
CHP types – simplified operation ranges
Opportunity costs of reserve provision in CHP portfolios
P
 1 degree of freedom
(i.e. backpressure turbines)
 0 degrees of freedom with
fixed heat production
𝑷𝒎𝒂𝒙
𝑷𝒎𝒊𝒏
𝑸𝒎𝒊𝒏
 2 degrees of freedom
(i.e. extraction condensing
turbines)
 1 degree of freedom with
fixed heat production
𝑸𝒅𝒆𝒎𝒂𝒏𝒅
𝑸𝒎𝒂𝒙
Q
P
𝑷𝒎𝒂𝒙
𝑷𝒎𝒊𝒏 (𝑸 = 𝟎)
𝑷𝒎𝒊𝒏
𝑸𝒎𝒊𝒏
𝑸𝒅𝒆𝒎𝒂𝒏𝒅
𝑸𝒎𝒂𝒙
Q
Other parts of CHP systems to be considered
Opportunity costs of reserve provision in CHP portfolios
 Heat system configurations rarely consist of CHP plants only which relaxes the rigid
characterization of heat restrictions
 Usually they are combined with heat boilers
 Peak demand coverage (especially during the winter)
 Back-up heat provision
 …
 Heat storages can provide further flexibility between time steps and even allow temporary
additional productionP
P
𝑷𝒎𝒂𝒙
𝑷𝒎𝒂𝒙
𝑷𝒎𝒊𝒏 (𝑸 = 𝟎)
𝑷𝒎𝒊𝒏
𝑷𝒎𝒊𝒏
𝑸𝒎𝒊𝒏
𝑸𝒅𝒆𝒎𝒂𝒏𝒅
𝑸𝒎𝒂𝒙
Q
𝑸𝒎𝒊𝒏
𝑸𝒅𝒆𝒎𝒂𝒏𝒅
𝑸𝒎𝒂𝒙
Q
The advantage of reserve provision by CHP plants
Opportunity costs of reserve provision in CHP portfolios
 Focus on extraction condensing turbines (with back-up heat provision):
P
𝑷𝒎𝒂𝒙
𝑷𝑹𝒆𝒔𝒆𝒓𝒗𝒆
𝑷𝑹𝒆𝒔𝒆𝒓𝒗𝒆,𝒄𝒂𝒍𝒍𝒆𝒅
𝑷𝒎𝒂𝒙 − 𝑷𝑹𝒆𝒔𝒆𝒓𝒗𝒆
𝑷𝒎𝒊𝒏 (𝑸 = 𝟎)
𝑷𝒎𝒊𝒏
𝑸ሶ 𝒏𝒆𝒘
𝑸ሶ 𝒃𝒆𝒇𝒐𝒓𝒆
Q
 Costs of positive reserve capacity provision (in this case)? 0!
The restriction by Pmax - PReserve is not binding for the optimal CHP operation point
 Costs of reserve energy provision?
Marginal costs of electricity – marginal costs of heat provision + marginal costs of alternative heat – start up
costs
27.04.2017
Minimum bids for one-sided reserve provision of nonconventional power plants– theoretical results
Opportunity costs of reserve provision in CHP portfolios
Negative Reserve
Max.(!) Efficient
Reserve
Provision Price
(≥) [€/MW]
෍
Positive Reserve
𝕀 𝑝𝑆𝑝𝑜𝑡 ≤𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑀𝐶𝑒𝑙 − 𝑝𝑆𝑝𝑜𝑡,𝑡
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
෍
𝕀 𝑝𝑆𝑝𝑜𝑡 ≥𝑀𝐶 𝑡 ∗ 𝐸𝑡 𝑝𝑆𝑝𝑜𝑡,𝑡 − 𝑀𝐶𝑒𝑙
𝑡∈𝑇𝑟𝑒𝑠𝑒𝑟𝑣𝑒
 Assume must-run condition in every hour of the reserve period
 Note: 𝑀𝐶𝑒𝑙 ≈ 30 − 50 €/𝑀𝑊ℎ𝑒𝑙 for CHP
There are almost no costs of reserve provision in average price hours!
If provision timeframes become even shorter, a clearing price of 0 is plausible for both positive
and negative reserve products
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Agenda
Marketing Flexibilities of a Simplified CHP Portfolio
Flexibility and its price
1
Reserve bids and spot prices – defining equilibria
2
Opportunity costs of reserve provision in CHP portfolios
3
Conclusions
4
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Implications
Conclusions
 Reserve provision prices reflect opportunity costs of
(i) keeping a plant running during reserve provision timeframes
(ii) withholding power bands and sub-optimal operation points
 The presented new technologies in the reserve markets can be expected to have had a significant
impact on reserve provision price levels
 The increasing number of small bids could imply that smaller units participate in the reserve markets
 There is a fundamental reason behind decreasing reserve prices, resulting from technologies like
CHP with low provision costs
 This effect will be amplified further by shorter provision timeframes
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Next steps
Conclusions
 Application of findings in a fundamental market model
 Identification of “fair” prices and derivation of their explanatory power regarding historical prices
 Determination of optimal bidding strategies for CHP plants
 Given local heat demand profiles
 Given longer time horizons of optimization (up to one week ahead)
 Construction of consistent stochastic spot and reserve price paths
 Is there a business case for CHP without feed-in-tariffs?
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Thank you for your attention!
Christian Furtwängler, M.Sc.
Chair for Management Science and Energy Economics,
University of Duisburg-Essen
Address: Berliner Platz 6-8, 45127 Essen, Room WST-C.11.17
Phone:
+49 201/183 6458
Mail:
[email protected]
4/27/2017
Sources
 Just (2011): “Appropriate contract durations in the German markets for on-line reserve capacity”, Journal of Regular
Economics, 39 (2011), S. 194-220
 Just, Weber (2008): “Pricing of reserves: Valuing system reserve capacity against spot prices in electricity markets”, 30
(2008), S. 3198-3221
 Bertsch et al. (2014): “Flexibility in Europe’s power sector – An additional requirement or an automatic complement?”
Energy Economics, 53 (2016), S. 118-131
 Baldursson et al. (2016): “Optimal reliability and reserve provision in electricity markets with increasing shares of
renewable energy sources – analytical insights”, IEEE International Energy Conference 2016, S. 1-6
 Gebrekiros et al. (2015): “Reserve procurement and transmission capacity reservation in the Northern European power
market”, International Journal of Electrical Power & Power Systems, 67 (3015), S. 546-559
 https://www.regelleistung.net/ext/tender/, joint transparency platform of the German TSOs, last visit: 13.04.2017 14:00
 https://www.netztransparenz.de/Weitere-Veroeffentlichungen/Solarenergie-Hochrechnung, joint transparency platform of
the German TSOs, last visit: 25.04.2017 15:00
 https://www.epexspot.com/en/market-data/, Spot price database of the European Power Exchange, last visit: 25.04.2017
15:05
 Presentation “Schaltungen von Kombiprozessen”, Fakultät für Ingenieurwissenschaften, Energietechnik, Universität
Duisburg-Essen
27.04.2017