1. Energy Economics

2. • Presentations

3. • Literature
– Taylor, G., Tanton, T. 2012. The hidden cost
of wind electricity. American tradition institute.
http://www.atinstitute.org/wp-content/uploads/2012/12/Hidden-Cost.pdf
– Hirth, L. 2013. The optimal share of variable
renewables. How the variabiity of wind and
solar power affects their welfare-optimizing
deployment. FEEM Working Paper 90.2013.
http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2351754
– Kirchen. Chapter 1

4. • How expensive are renewables
after all?

5. The technology behind crystalline
silicon solar cells has profited from
extensive developments in the multi-
billion-dollar microelectronics
industry.
About 20 years ago, a kilowatt of
solar energy cost about 50 euro
cents ($0.69) to produce, today in
Germany it's about 10 euro cents -
while in sunny regions it's between
5 and 8 euro cents.
So worldwide, we're totally
competitive with, and often even
cheaper than, fossil fuels.
http://www.dw.de/at-the-floodgates-of-a-solar-energy-boom/a-17259267
Professor Eicke R. Weber is
the Director of the
Fraunhofer Institute for Solar
Energy Systems ISE and
professor of physics/solar
energy at the Department of
Mathematics and Physics
and the Department of
Engineering respectively at
the University of Freiburg,
Germany.
http://www.ise.fraunhofer.de/en/about-us/director-and-division-direc
Can this be true?
Why give subsidies still?

6. • http://www.cityam.com/article/1392944530/how-free-markets-are-making-solar-energy-feasible-without-subsidies

7. http://cleantechnica.com/2013/12/16/solar-gird-parity-infographic-important-addendum/

8. http://solarcellcentral.com/cost_page.html

9. 2013
€1-2/W
Capital costs of PV have fallen with 85%-90% since 1998
(from $12 -> $1-2 per Wpc)

11. http://www.ise.fraunhofer.de/en/publications/veroeffentlichungen-pdf-dateien-en/studien-und-konzeptpapiere/study-levelized-cost-of-electricity-renewable-energies.pdf/view

12. • Refinements:
1. Explicitly model intermittent (solar+wind) +
backup
2. Model the value of electricity produced by
intermittent generation

13. 1. Explicitly model intermittent (solar+wind)
+ backup

14. • Wind and solar should better be seen as:
– Wind and solar + gas backup (round 90%)
– Wind and solar + coal backup (round 90%)

15. • Taylor, G., Tanton, T. 2012. The hidden
cost of wind electricity. American tradition
institute. http://www.atinstitute.org/wp-
content/uploads/2012/12/Hidden-Cost.pdf

16. Source: Energy Information Administration 2012 Annual Energy Outlook

20. Source: Energy Information Administration 2012 Annual Energy Outlook

21. • This report has shown that the cost wind
electricity is not approaching parity with
conventional sources, and is unlikely to
reach parity
– unless the price of natural gas, the price of
coal and the capital cost of nuclear facilities
were all to increase dramatically.

22. • Study applies to US
– 3% of energy generated by wind
• Germany
– Has higher wind penetration
– 7~8% of energy generated by wind
• What is the effect of an increase in wind
penetration on costs?

23. 2. Model the value of electricity produced
by intermittent generation

24. • Hirth, L. 2013. The optimal share of
variable renewables. How the variabiity of
wind and solar power affects their welfare-
optimizing deployment. FEEM Working
Paper 90.2013.
http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2351754

26. Levelized costs:
Levelized value:
Where (exact):
Over lead
times
Over timesOver places
Approximation

28. • We define profile costs as the price spread between the load-
weighted and wind-weighted day-ahead electricity price for all hours
during one year. Profile costs arise because of two reasons. On the
one hand, demand and VRE generation are often (positively or
negatively) correlated. A positive correlation, for example the
seasonal correlation of winds with demand in Western Europe,
increases the value of wind power, leading to negative profile costs.
• On the other hand, at significant installed capacity, wind
“cannibalizes” itself because the extra electricity supply depresses
the market price whenever wind is blowing. In other words, the price
for electricity is low during windy hours when most wind power is
generated. Fundamentally, profile costs exist because electricity
storage is costly, recall physical constraint i). A discussion of profile
costs and quantitative estimates are provided by Lamont (2008),
Borenstein (2008), Joskow (2011), Mills & Wiser (2012), Nicolosi
(2012), Hirth (2013), and Schmalensee (2013).

29. • wind “cannibalizes” itself because the
extra electricity supply depresses the
market price whenever wind is blowing

30. Remember how wind was cannabalized in the model of lecture W07.2F

31. • Profile cost: wind produces most when the price is low

34. • Profile cost: wind produces most when the price is low
• Balancing cost: forecasting errors
– wind produces is “out-of-balance”, produces more or less than
promised
– Cycling costs of plants

35. • Profile cost: wind produces most when the price is low
• Balancing cost: forecasting errors
– wind produces is “out-of-balance”, produces more or less than promised
– Cycling costs of plants

36. European Climate
Foundation 2050:
• Increase from 34
GW to 127 GW
• 400% increase
The future of the EU transmission network
Authors wont model the
losses due to location
(grid costs) were not
modeled

37. • Profile cost: wind produces most when the price is low
• Balancing cost: forecasting errors
– wind produces is “out-of-balance”, produces more or less than promised
– Cycling costs of plants
• Grid costs: wind produces far away from demand
– Cost of additional transmission

38. • Cost change with penetration
(cannabilization effect)

41. • So far are theoretical models, what do the
numbers tell us?
– Use of a dispatch model, feeding realistic data
– Northwestern Europe: Germany, Belgium,
Poland, The Netherlands, and France

42. 3% 20%
Wind

43. Wind

44. If wind blew constantly
If wind was variable but
perfectly predictable
True situation
Note that losses due to
location (grid costs)
were not modeled
LCoE use the simplification that wind blows constantly.
This simplification seems to explains the wide gap in the debate on
the usefulness of wind.

45. Assuming 30% fall in wind cost wrt today

46. • What is remarkable about this curve?
• Optimal wind share with doubling of:
– Coal price -> increases
– Gas price -> decreases

47. • Doubling coal prices -> optimal wind up by
5% points
• Halving gas prices (“shale gas”) -> optimal
wind down
• Doubling gas prices -> optimal wind down.

48. • Doubling coal prices -> optimal wind up by 5%
pointsfive percentage points (Figure 17).
• Lowering gas prices by half (“shale gas”) has a
similarly expected effect,dramatically lowering
optimal wind deployment.
• Surprisingly however, doubling gas prices
reduces the optimal wind share.
– As in the case of CO2 pricing, the reason for this
seemingly counterintuitive result can be found in the
capital stock response to the price shock. Higher gas
prices induce investments in hard coal, which has
lower variable costs, reducing the value of wind power
and its optimal deployment.

49. Solar
• Even at 60% cost reduction, the optimal solar share is
below 4% in all but very few cases.
• Reason: the marginal value of solar power drops steeply
with penetration,
– Even more so than wind. Why?
– Because solar radiation is concentrated in few hours
• In line with earlier studies (Nicolosi 2012, Mills & Wiser
2012, Hirth 2013).
Now: €1-2/W
Hirth + 60% cost reduction:€0.6/WHirth uses€1.6/W

50. 2013
€1-2/W

51. http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy-2013.html

54. • Energy revolutions

55. http://vaclavsmil.com/wp-content/uploads/scientificamerican0114-52.pdf

56. • Coal supplies more than 5 percent of
energy
– 1840
• fossil fuels (coal) surpasses use of
biomass (wood and charcoal)
– 1885 USA
– 1875 France
– 1901 Japan
– 1930 U.S.S.R
– 1965 China
– 1970 India

57. • Oil supplies more than 5 percent of energy
– 1915
• Oil surpasses use coal
– 1964

58. Organization of
electricity markets

59. • Organization of electricity markets
1. Liberalization
2. Transmission pricing (Nodal versus Zonal)

60. • Organization of electricity markets
1. Liberalization
Kirchen. Chapter 1

62. Allow Independent Power Producers (IPP)
(US: PURPA law 1978)

64. Add wholesale competition

65. Add retail competition
Close to the present model in EU
(but wholesale market and transmission system
are separate)

66. Unbundling was a
process over
several years
S. van Koten, A. Ortmann
/ Energy Economics 30
(2008) 3128–3140

69. Unbundling was a
process over
several years
S. van Koten, A. Ortmann
/ Energy Economics 30
(2008) 3128–3140

70. Unbundling was a process over several years
S. van Koten, A. Ortmann / Energy Economics 30 (2008) 3128–3140
http://www.cerge-ei.cz/pdf/pb/PB13.pdf

71. • Organization of electricity markets
1. Liberalization
2. Transmission pricing

72. • Nodal and zonal dispatch in meshed
networks
• Peak-load pricing

73. 900MW
@20$/MWh
800MW
@50$/MWh
900MW
@20$/MWh
800MW
@50$/MWh
Nodal pricing Zonal pricing
A B
400MW 300MW 400MW 300MW
A B

74. A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
400MW 300MW
@20$/MWh @20$/MWh
300MW
400MW 300MW
@20$/MWh @20$/MWh
300MW
Nodal pricing Zonal pricing
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
A B
Bids for ancillary market
(balancing market)
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh

75. A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
400MW 300MW
@20$/MWh @50$/MWh
200MW
400MW 300MW
@20$/MWh @20$/MWh
300MW
Nodal pricing Zonal pricing
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
Max: 200MWMax: 200MW
@30$/MWh
Price of transmission?
20
50
900 1700700
1st
dispatch

76. A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
400MW 300MW
@20$/MWh @50$/MWh
200MW
400MW 300MW
@20$/MWh @20$/MWh
200MW
Nodal pricing Zonal pricing
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
Max: 200MWMax: 200MW
@30$/MWh
Price of transmission?
20
50
900 1700700
-100MW @-10$
= +10.000$
+100MW @70$
= -80.000$
Cost of 70.000
1st
dispatch
2nd dispatch

77. A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
400MW 300MW
@20$/MWh @50$/MWh
200MW
400MW 300MW
@30$/MWh @30$/MWh
200MW
Nodal pricing Zonal pricing
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
A B
900MW
@20$/MWh
+ @35$/MWh
- (@-10$/MWh
800MW
@50$/MWh
+ @70$/MWh
- (@-20$/MWh
Max: 200MWMax: 200MW
@30$/MWh
Price of transmission?
20
50
900 1700700
2nd dispatch
-100MW @-10$
= +10.000$
+100MW @70$
= -80.000$
1st
dispatch

78. 40MW
A B
40MW
Limit: 50MW
Limit: 50MW
Net
Withdraw:
80MW
Net
Injection:
80MW

79. 3 node network

80. A
B
Injection: 120MW
С
Demand: 120MW
Withdrawal: 120MW
70$/MWh
40MW80MW
40MW
Marginal Cost?
Dispatch with 3
nodes
30$/MWh
30$/MWh

81. A
B
Injection: 120MW
С
Demand: 120MW
Withdrawal: 120MW
70$/MWh
40MW80MW
40MW
Dispatch with 3
nodes
30$/MWh
Limit: 500MW
Limit: 20MW
Limits

82. Demand: 120MW
Withdrawal: 120MW
A
B
Injection: 120MW
С
Limit: 500MW
Limit: 20MW
40MW80MW
40MW
Injection: 60MW
20MW
20MW
60MW
30$/MWh 60MWh is shed!
Solution 1?:
lower injection
40MW
70$/MWh
30$/MWh
Limits

83. Demand: 120MW
Withdrawal: 120MW
A:40M
W
A
B
Injection: 120MW
30$/MWh
С
Limit: 500MW
Limit: 20MW
70$/MWh
A:80M
W
A: 40MW
Solution 2?: Add
counter flow
Inject 60 MWB:20M
W
B:20M
W
B: 40MW180MW
ANET:20M
W
Limits

84. A:40M
W
A
B
Injection: 120MW
30$/MWh
С
Limit: 500MW
Limit: 20MW
70$/MWh
A:80M
W
A: 40MW
Solution 3:
Counter flow &
proportional
downturning
Inject 60 MWB:20M
W
B:20M
W
B: 40MW
Injection: 80MW
30$/MWh
A:53.33
M
W
A:26.67M
W
A: 26.67 MW
Inject 40 MW
B:13.33M
W
B:13.33M
W
B: 26.67 MW
Demand: 120MW
Withdrawal: 180MW120MW

85. • Up till 60MW from A no problem

86. A
B
Injection: 60MW
30$/MWh
С
Limit: 500MW
Limit: 20MW
70$/MWh
A:20MWA:40MW
A: 20MW
Limits
Demand: 120MW
Withdrawal: 60MW

87. A: +⅓ MW
A: 20MW
A
B
Injection: 60MW
30$/MWh
С
Limit: 500MW
Limit: 20MW
70$/MWh
A: 40MW
A: 20MW
Limits
+1 MW
B: + ⅓ MW
+1 MW
Demand: 120MW
Withdrawal: 60MW

88. A:+10 MW
A: 20MW
A
B
Injection: 60MW
30$/MWh
С
Limit: 500MW
Limit: 20MW
A: 40MW
A: 20MW
Limits
+30 MW
B: +10 MW
+30 MW
70$/MWhDemand: 120MW
Withdrawal: 60MW
A: 30MW
A: 60MW
B: 20MW
B: 10MW
90MW120MW
Marginal Cost? 50$/MWh

89. • When
– A can inject maximally 90MW?
– And B increases demand with 10MW
• what is then the MC and AC?

90. • Nodal & Zonal
• Peak-load pricing

91. Peak-load pricing
Example: Transmission interconnector line
ST-MC
Off-peak
Peak
LT-MC
Ppeak
POff-peak=0
91

92. Peak-load pricing
Gives clear economic signals!
ST-MC
Off-peak
Peak
LT-MC
Ppeak
POff-peak=0
92
ST-MC
Off-peak
Peak
LT-MC
Ppeak
POff-peak=0
Invest in expansion
of transmission
capacity on the line
Do not invest in expansion
(wait or even remove a line)

93. Zonal pricing -> averaging
(EU)
Nodal pricing (also Locational Marginal
Pricing) -> peak-load pricing
(USA)

94. Peak-load pricing
Example: Transmission interconnector line
ST-MC
Off-peak
Peak
LT-MC
POff-peak
Ppeak
PAVERAGE
94