Electricity Generation

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1 Electricity Generation Understanding generation and dispatch (Session 4) Yerim Park & Dennis Volk IEA Electricity System Training Week, Bangkok, November 2013

3 Global Electricity Capacity 9760 GW in 2035

Generation technology types and their qualities Economic

CCS commercial viability, uncertain costs COAL GAS

high costs for baseload Regional security of supply

CAPEX, longest lead times Safety, waste disposal,

4 Generation technology types and their qualities Economic competitiveness Carbon, environmental, transport costs effects CCS commercial viability, uncertain costs COAL GAS Flexibility: hedging financial risk, low carbon Relatively high costs for baseload Regional security of supply Significant carbon-free baseload Long term stable costs High CAPEX, longest lead times Safety, waste disposal, decommissioning NUCLEAR RENEWABLES Non-carbon options Variability, unpredictability Decreasing capital costs

5 Levelised Costs of Electricity (LCOE) comparative cost breakdown analysis 160,00 140,00 120,00 100,00 80,00 60,00 40,00 20,00 0,00 Nuclear Coal Coal w/carbon Capture (90%) Gas Wind Total Capital Cost Fuel Costs Carbon Costs (SO2 if app.) Operations and Maint. Waste Management

6 Nuclear is largely dependent on total investment costs determined by construction costs & the discount rate

7 Fuel cost is the most important cost parameter of gasfired power plants

8 Coal-fired plants are sensitive to variations in carbon costs at low discount rate, construction costs in high discount case

9 Coal w/ccs are highly sensitive to investment costs at both discount rates

10 Onshore wind is very sensitive to load factor variations

11 so is Solar PV, and both are also sensitive to construction costs

12 Risks associated with generation technologies No single generating technology can be cheapest in all situations specific circumstances of each project The investment decision is a complex process *Projected Costs of Generating Electricity, 2010, IEA

13 Exercise Decomposing generation costs You have a model with five plants in three regions The next slide shows you cost differences by region and technology Try to fulfill the following tasks in your region Investments: which technology would you pick by region Investments: identify key sensitivities which can influence your choice Investments: consider the role of carbon pricing to influence your choice Operations: Identify operational costs per technology and region

14 Investment costs [USD/kW]: Hard coal CCGT OCGT. 500 Nuclear Onshore wind Efficiency [%]: Hard coal. 45 CCGT. 60 OCGT. 40 Nuclear. 35 Onshore wind. Cost of capital [%]: Hard coal. 7 CCGT. 7 OCGT. 10 Nuclear. 10 Construction time [yrs]: Hard coal. 6 CCGT. 3 OCGT. 2 Nuclear. 10 Onshore wind. 1 Fuel price [USD/GJ]: Hard coal. 3 CCGT. 5 OCGT. 5 Nuclear. 3 Onshore wind. 10 Onshore wind. 0 Fuel price [USD/GJ]: Hard coal. 5 CCGT. 7 OCGT. 7 Nuclear. 3 Investment costs [USD/kW]: Hard coal CCGT OCGT. 500 Nuclear CCGT. 13 Onshore wind. Onshore wind Efficiency [%]: Hard coal. 45 CCGT. 60 OCGT. 40 Nuclear. 35 Onshore wind. Construction time [yrs]: Hard coal. 6 CCGT. 3 OCGT. 2 Nuclear. 10 Onshore wind. 1 CO2 price: 15 USD/tCO2 Cost of capital [%]: Hard coal. 7 CCGT. 7 OCGT. 10 Nuclear. 10 Onshore wind. 10 Fuel price [USD/GJ]: Hard coal. 4 OCGT. 13 Nuclear. 3 Onshore wind. Efficiency [%]: Hard coal. 40 CCGT. 55 OCGT. 35 Nuclear. 35 Onshore wind. Investment costs [USD/kW]: Hard coal CCGT. 750 OCGT. 500 Nuclear Onshore wind Construction time [yrs]: Hard coal. 6 CCGT. 3 OCGT. 2 Nuclear. 10 Onshore wind. 1 Cost of capital [%]: Hard coal. 7 CCGT. 10 OCGT. 10 Nuclear. 10

15 INT001 INT004 INT007 INT010 INT013 INT016 INT019 INT022 INT025 INT028 INT031 INT034 INT037 INT040 INT043 INT046 INT049 INT052 INT055 INT058 INT061 INT064 INT067 INT070 INT073 INT076 INT079 INT082 INT085 INT088 INT091 INT094 Load Market operations varying demand calling for supply Texas Daily Load Curves in 2012 February August

16 GENERATION Bidding for dispatch Marginal pricing applied under good competition Operational costs determines ranking order of individual plants bids, i.e. their competitiveness Highest required bid to determine the market price Fuel costs O & M Efficiency Price per MWh

17 GENERATION Bidding for dispatch Coal plant Gas plant A - CCGT 5 USD/MBtu 55% Gas plant B - OCGT 50 USD/t 42% efficiency 35 USD/MWh 40 USD/MWh 125 USD/MWh Wholesale market (day-ahead and intra-day) 5 USD/MBtu 35% efficiency Ranking order: Coal, Gas A, Gas B

18 USD/MWh Not dispatched Not dispatched WHOLESALE How competitive price formation works NYISO marginal pricing as example 1am Market 1am Our coal plant 12pm Our gas plant A Our gas plant B Cumul. capacity (MW)

19 USD/MWh WHOLESALE CAPEX recovery as part of marginal pricing through infra-marginal rents Infra-marginal rents IMR: USD/MWh = 45 USD/MWh IMR: 40 USD/MWh Our coal plant Our gas plant A Cumul. capacity (MW)

20 USD/MWh Infra-marginal rents: why they matter? Infra-marginal (IR) rents are the difference between the market price and the individual plants production costs IR are no pure profits they cover investment costs plus margin Gas - CCGT Hard coal Nuclear CCGT sets market 80 USD/MWh For coal, IR 80 minus 35 USD/MWh OPEX CAPEX

21 Jan-03 Sep-03 May-04 Jan-05 Sep-05 May-06 Jan-07 Sep-07 May-08 Jan-09 Sep-09 May-10 Jan-11 Sep-11 May-12 Jan-13 USD/MWh US gas and coal prices influence generation costs 100 US power generation costs by fuel Gas Coal

22 TWh US fuel costs trigger gas growth and coal-to-gas switch 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, US power generation by source Coal to gas: Factor >2 Coal to gas: Factor <1.2 Coal Gas Total

23 h/a So why did not more switch happen? Territorial differences OCGTs remain online Coal supply contracts (max 10 yrs) System service provision and transmission constraints Lignite remains competitive (5% of total coal) 75% of coal under regulation. Impact unclear (IEA, 2013 and Knittel, 2002) Observed elasticity: 1.4% at 10% coal-to-gas (EIA, 2012) Natural Gas Coal Nuclear

24 annual capacity additions [GW] Economics attracted new generation in US Natural Gas Coal Nuclear Other Sources

25 GW Long-term reliability in Texas now its about the peak Existing units Planned units Peak 13.75% reserve margin Data source: Brattle, 2012

26 USD/MWh Marginal pricing for peakers what price really? No infra-marginal unless rents prices for peakers go up, to? Cumul. capacity (MW)

27 Current concerns in Texas Low market prices due to gas market developments Reduced infra-marginal rents in the market, also for peaking plants Administered reserve margin of 13.75% exceeds price cap Target set by governments for 10 in ten events Capped spot market prices Peaking plants cannot fully compensate during peaks Price increase from 4500 USD/MWh to 9000 USD/MWh (by June % reserve margins achievable) No allowance to enter into long-term contracts Insufficient demand side participation Insufficient price for balancing services Texas to remain keen to preserve MWh payments ( energy-only ) instead of using capacity payments (used in rest of US, Chile, some EU)

28 List of references Brattle, 2012: ERCOT Investment Incentives and Resource Adequacy, available at 01.pdf. EIA, 2012: Fuel Competition in Power Generation and Elasticities of Substitution, available at IEA, 2013: Gas to Coal Competition in the U.S. Power Sector, available at Knittel, C., 2002: Alternative Regulatory Methods and Firm Efficiency: Stochastic Frontier Evidence from the U.S. Electricity Industry, The Review of Economics and Statistics, Massachusetts Institute of Technology, Massachusetts, August, 84(3): PUCT, 2006: The Texas Energy-Only Resource Adequacy Mechanism, available at UK Gov, 2013: Maintaining UK energy security, available at

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