The price of energy security in depressed electricity markets; the case of Belgium Prof.Dr. Johan Albrecht Faculteit Economie & Bedrijfskunde Second Summer School Economics of Electricity Markets 28/08/2014

Structure The Belgian context ‘Security of supply’ has two dimensions: follow peak demand & avoid excessive overproduction (intermittent RES) ‘No Policy’ scenario; not sustainable ‘Security of supply’ scenarios ; new assets, old thermal assets, DSM & combinations Surplus risk assessment Conclusions

The Belgian Context Firm capacity of MW ( MW today) Nuclear phase-out: MW

Changing Load Factors (LF)

RES Gas

Wholesale prices in CWE

Peak Load; decreasing?

Plan Wathelet Extension Tihange 1, 800 MW CCGT, 400 MW DSM

Reserve Margin (RM) 2012/2013

RM in ‘No Policy’ scenario

Supply scenarios for Belgium Policy options; incentives for flexible generation (new and old termal), DSM, CFD for RES (with/without Market Participation (MP)) Investment and system cost of policy options? (with 8% discount rate, LCOE-approach) Assumptions on context; peak demand + 0,5%/yr, carbon price up to € 40 per ton CO 2 in 2030, endogenous price model (more RES -> lower wholesale prices), network costs increase with RES share

LCOE assumptions

Endogenous price model

Prices in NEA for DE

Network costs as f(RES)

Security of supply; RM > 5% at all times IF (‘No Policy’ RM < 5%) THEN model triggers CCGT, OCGT & Biomass investments Context: old thermal, DSM, BAU RES and High RES

New capacity; split up

Incentive schemes Capacity payments for CCGT (€ 900/kW), OCGT (€ 700/kW) and Biomass (€ 1050/kW) RES support per MWh (incl. Biomass) ; CFD = LCOE minus price CFD-MP includes curtailment (max 5% PV, max 14% wind) CFD-MP; lower LF, higher LCOE, higher CFD

Old Thermal & DSM end of MW OT scheduled for ; in reserve capacity, 5% € 95/MWh (€ 50 to 60 mill) DSM clearing prices of € 150/MW/day (based on UBS)

Firm capacity in 2030; 18 GW / RM 9% Peak demand of 14,7 GW in 2030 Gas dominates / old thermal; end of life in 2024 Biomass; – MW in BAU RES / – MW in High RES

Total capacity in 2030; 25 – 30 GW

Electricity production in 2030 CFD-MP; Biomass used in flexible way -> higher LF for CCGT Share of RES in 2030: from 28% in BAU RES CFD-MP to 60% in High RES CFD

Generation portfolio LF

WP Bureau Fédéral du Plan, 2013

Annual subsidy cost: cap pay + CFD All results: additional to subsidy cost of 2014 One-off capacity payments in year of investment

Cumulative cost up to 2030; € 21 and € 41 bill -> MP of RES matters!

Optimal frameworks and RES share? Trade-off between RES share and costs is not linear

LCOE generation mix,

Total annual system costs (gen+netw)

Total costs and RES share

Cumulative System Costs

Cumulative System Costs & RES-share (2030)

Cumulative Subsidy Costs & Cumulative System Costs ( )

Surplus risks? Only with ‘New Capacity’ scenarios Random PV & wind generation in Matlab ( patterns), based on Elia ‘Must-run’; biomass (MP), CHP & nuclear Compared to demand variation in 15 min intervals Demand (15 min) (RES + Must Run) Export capacity of MW; surplus of is problematic DSM (to increase demand); here not included

Illustration of PV+wind output for 29 days

2014 Surplus Risk

2017 Surplus Risk

2023 Surplus Risk

2027 Surplus Risk

Overview Surplus Analysis

Nuclear prolongation; 3 GW NUC in 2030

Conclusions 1

Conclusions 2 To secure 5% RM, cumulative subsidy costs up to 2030 vary between € 21 and € 41 billion Smart policy choices will lower costs for society, even at relatively high RES shares Market participation by RES is essential to facilitate further expansion of RES DSM lowers costs / Old thermal; limited relevance limitations of this analysis; capacity payments as institutional challenge (end of EOM?), recovery of demand, delocalisation energy-intensive industries, evolution of interconnection, arrival of smart grid, share of electric vehicles by 2030, EC climate policies,…

Thank you for your attention Second Summer School ‘Economics of Electricity Ghent University, August 25-29, dex.htm dex.htm