Offshore Wind Economics under EMR: Quantifying the risks
Daniel Radov - Associate Director, Environment Practice (presenting) Dr. Mauricio Bermudez-Neubauer - Associate Director, Environment Practice
Aberdeen May 21, 2014 Under EMR, support for offshore wind and other renewables in the GB market is changing, transforming the risk landscape for investors
Renewable Obligation (RO) Feed in Tariff with Contract for Difference (CfD)
P£/MWh P£/MWh
Rebate P
P*>Pwholesale
Pmarket
Pmarket
Time Time
Price received is Price received is volatile and fixed* : market uncertain: market price plus a price plus a fixed variable top-up. * Subject to price > 0 top-up.
Although the CfD-FiT was created to remove price risk, investors will still remain exposed to market and other risks, some of which are intrinsic to the CfD scheme 1 1 Wholesale Power Price Risk Investors in wind assets under the CfD FiT will 2 Volume Risk face a number of risks that need to be 3 Basis/Balancing Risk understood and managed 4 Allocation Risk
Market / Allocation Risks
1 Wholesale Power Price Risk In scope of our presentation today 2 Volume Risk
3 Basis/Balancing Risk
4 Allocation Risk
5 Construction Delay Risk
Regulatory Risks
Change in Regulation Risk
NERA helped UK government’s Department of Energy and Climate change assess the different risk exposure for investors under CfDs vs. the RO regime 2 1 Wholesale Power Price Risk Both power prices and wind load factors drive 2 Volume Risk 3 Basis/Balancing Risk
revenue volatility for wind assets 4 Allocation Risk
Simulated Wholesale Power Price Revenue Impact of Power Price: CfD
180 Period of Operation 700 1 Wholesale Power 160 600 140 500 Price Risk 120
100 95% CI 400 95% CI 80 75% CI £/kW 300 75% CI 60 50% CI 50% CI 40 200 Average
Electricity (£/MWh) Price Electricity Average 20 100 CfD’s leave assets - exposed to power 0
2003 2008 2013 2018 2023 2028 2033 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 prices from year Year Year of Operation 15 onwards
Load Factors Revenue Impact of Load Factor Load Factor Load factors are correlated: 30% limits diversification potential Revenues (£/kW) Load factor risk is 2 Volume Risk 25% 900 likely to cancel out 800 20% in the long run 700 15% 600 95% CI 500 75% CI 10% 400 50% CI 5% 300 Average 200 0% 100 0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 South West North West Center 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 East Portfolio Load Factor 5th Percentile Year of Operation 95th Percentile
CfDs reduce power price risk but wind assets are still exposed to volume risk
(and its interaction with price risk) 3 Source : NERA analysis 1 Wholesale Power Price Risk
Assets with CfDs face basis risk, because the 2 Volume Risk reference price from which support payments 3 Basis/Balancing Risk are calculated is the hourly day-ahead price 4 Allocation Risk
Day-Ahead Auction Gate Closure (e.g. 11am) 1h before delivery Forward market Intraday market Balancing Delivery window
Electricity Basis Risk Before Gate Closure Balancing Risk price for delivery in hour T PDAM
Basis / Balancing
PBalancing risk
T t CfD payment is based on Day- Ahead Market (DAM) price Price at delivery may differ from Day-Ahead Market price
This basis risk is asymmetric and difficult to diversify
4 Increased RES penetration is likely to create 1 Wholesale Power Price Risk 2 Volume Risk a negative correlation between renewable 3 Basis/Balancing Risk generation (RES) output shocks and intraday / 4 Allocation Risk balancing price shocks
Merit Order Determines Expected Price on Positive Output Shock Lowers the Price Day-Ahead Market Relative to Day-Ahead Market Load (demand) £/MWh Merit Order Price shock
PDAM Basis / Balancing risk Pshock
MWh* MWh MWh*
Expected day-ahead Unexpected actual output from wind output from wind
Wind output is correlated, so unexpectedly high output (“positive shocks”) are likely to depress the intraday/balancing market price, and vice versa. 5 1 Wholesale Power Price Risk Trading strategies differ in their expected 2 Volume Risk cash flow volatility and mean value – 3 Basis/Balancing Risk depending on market and regulatory design 4 Allocation Risk
. Strategy 1: Sell expected generation on the day-ahead market, balance on intraday/balancing
. Strategy 2: Sell all output on balancing/intraday market
Output Uncorrelated with Captured Price Output Correlated with Captured Price
Daily cash flow volatility cancels out Basis / Balancing costs become more (annual cost = zero) only if significant when RES assets’ output is all balancing arrangements are “symmetric” correlated, leading to negative correlation and un-correlated with output with prices.
Frequency Basis / Balancing 60% Basis / Balancing cost = 0 50% cost > 0 Strategy 1: Sell expected on day-ahead Strategy 1 Mean 40% Strategy 2: Sell actual on within-day 30% Strategy 2 Mean 20%
10%
0% -40% -30% -20% -10% 0% 10% 20% 30% 40% Gain (Loss) from Within-Day Trading Relative to Reference Price
Basis / balancing risks impose costs when asset output is negatively correlated with price – market modelling can assess this correlation. 6 Source : NERA analysis 1 Wholesale Power Price Risk
2 Volume Risk As a result, CfD assets are not risk-free – 3 Basis/Balancing Risk even following construction 4 Allocation Risk
Cash Flow risk, Individual Year NPV, Life of Asset
Volume Risk Volume Risk
Basis & Balancing Risk Basis & Balancing Risk
Electricity Price Risk Electricity Price Risk
Overall 5% VaR Overall 5% VaR
-40% -30% -20% -10% 0% 10% 20% 30% Cashflow in Individual Year -30% -20% -10% 0% 10% 20% 30% NPV over Asset Life
. Figures show P5 / P95, downside / . Over asset life, volume risk averages out upside cases . Price-related risks remain under CfDs . In single years, volume risk clearly dominates . Basis/balancing risk depends on regulatory and market characteristics
Through market and output simulation, value at risk can be quantified and correlated with market parameters, to better understand risk to contracted output. 7 Source : NERA analysis 1 Wholesale Power Price Risk Levy Control Framework (LCF) creates a 2 Volume Risk significant risk that projects will not secure 3 Basis/Balancing Risk support 4 Allocation Risk
Projections of Levy Expenditure vs. Budget Categories receiving support . Existing and new Small-scale FIT . Existing and new RO-supported capacity . FIDER CfD projects . Established CfD-supported . Less established CfD-supported
Factors affecting Levy Expenditure . Electricity prices (see next slide) . RES uptake in different categories . Strike prices awarded (via auction) . RES output
Source: NERA analysis of data from DECC EMR, National Grid and industry sources.
8 1 Wholesale Power Price Risk Risk of breaching LCF increases with lower 2 Volume Risk wholesale power price, as CfD support 3 Basis/Balancing Risk requirement increases 4 Allocation Risk
Simulated Power Prices Projected Total LCF Budget Spent
Developers and investors should understand how uncertainty about power prices and other factors affects budget availability and project economics.
9 Source : NERA analysis 1 Wholesale Power Price Risk Allocation of CFD support: implementation of 2 Volume Risk auctions and detailed auction design allow 3 Basis/Balancing Risk government significant discretion 4 Allocation Risk
Sample Profile of Incremental LCF Budget Expenditure
LCF Budget . Government has discretion about £ Allocation of budget allocation of funding to technology between technology Less established: groups is uncertain “pots” – and ultimately between Offshore wind Biomass CHP projects Tidal/wave . Projects seeking funding need to ACT understand AD Geothermal . cost relative to other bidders in the “merit order” Established: Onshore wind . how clearing price could vary with Solar PV auction year Hydro Landfill gas . potential dependence of available Sewage gas budget on other market EfW CHP parameters (e.g. output, power prices) Year . There may be opportunities for strategic bidding – understanding when LCF looks tight and when it is less constrained
10 Conclusions / Key Takeaways
. New FiT CfD regime reduces exposure to some risks, but increases others: – Volume risk remains significant, but averages out to lower level over asset lifetime – Basis/balancing risk imposes costs that depend on how much other wind is on the system – impact on value at risk can be significant – Wholesale price risk returns after year 15, limited significance because of discounting – Some of the reduction in wholesale price risk “transmuted” to allocation risk for new projects
. Allocation risk is a significant concern: – With low wholesale power prices (e.g. from greater renewables output) there is increased risk that the LCF cap is breached. – Bid strategy needs to consider timing of LCF budget constraint and of competing projects. – Even with use of “objective” auction mechanism to select projects, significant regulatory discretion remains to tip balance in favour of projects and technologies
Impact of changes in risk profile on overall financing costs is mixed.
Developers, owner-operators and investors who understand and quantify these risk factors can maximise the value realised from their investments. 11 Thank you.
Contact
Daniel Radov Dr. Mauricio Bermudez-Neubauer Associate Director – Energy & Environment Associate Director, Energy & Environment London London [email protected] [email protected]