Offshore Wind Economics under EMR: Quantifying the risks

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1 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, 0

2 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 P ROC P Strike Rebate P*<P wholesale Top Up P*>P wholesale P market P market Time Time Price received is volatile and uncertain: market price plus a fixed top-up. Price received is fixed* : market price plus a variable top-up. * Subject to price > 0 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

3 Investors in wind assets under the CfD FiT will face a number of risks that need to be understood and managed Market / s 5 Construction Delay Risk In scope of our presentation today 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

4 Both power prices and wind load factors drive revenue volatility for wind assets Simulated Wholesale Power Price Revenue Impact of Power Price: CfD Wholesale Power Price Risk Electricity Price ( /MWh) Period of Operation Year 95% CI 75% CI 50% CI Average /kw Year of Operation 95% CI 75% CI 50% CI Average CfD s leave assets exposed to power prices from year 5 onwards Load Factors Load Factor 0% 5% 0% 5% 0% 5% 0% Load factors are correlated: limits diversification potential South West North West Center East Portfolio Load Factor 5th Percentile 95th Percentile Revenue Impact of Load Factor Revenues ( /kw) Year of Operation 95% CI 75% CI 50% CI Average Load factor risk is likely to cancel out in the long run CfDs reduce power price risk but wind assets are still exposed to volume risk (and its interaction with price risk) Source : NERA analysis

5 Assets with CfDs face basis risk, because the reference price from which support payments are calculated is the hourly day-ahead price Day-Ahead Auction (e.g. am) Gate Closure h before delivery Forward market Intraday market Balancing Delivery window Electricity price for delivery in hour T Basis Risk Before Gate Closure P DAM Balancing Risk P Balancing Basis / Balancing risk CfD payment is based on Day- Ahead Market (DAM) price T Price at delivery may differ from Day-Ahead Market price t This basis risk is asymmetric and difficult to diversify

6 Increased RES penetration is likely to create a negative correlation between renewable generation (RES) output shocks and intraday / balancing price shocks Merit Order Determines Expected Price on Day-Ahead Market Positive Output Shock Lowers the Price Relative to Day-Ahead Market /MWh Load (demand) Merit Order Price shock P DAM P shock Basis / Balancing risk MWh* MWh MWh* Expected day-ahead output from wind Unexpected actual 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

7 Trading strategies differ in their expected cash flow volatility and mean value depending on market and regulatory design Strategy : Sell expected generation on the day-ahead market, balance on intraday/balancing Strategy : Sell all output on balancing/intraday market Output Uncorrelated with Captured Price Output Correlated with Captured Price Daily cash flow volatility cancels out (annual cost = zero) only if balancing arrangements are symmetric and un-correlated with output Basis / Balancing costs become more significant when RES assets output is all correlated, leading to negative correlation with prices. Basis / Balancing cost = 0 Frequency 60% 50% 0% 0% 0% 0% Basis / Balancing cost > 0 Strategy : Sell expected on day-ahead Strategy Mean Strategy : Sell actual on within-day Strategy Mean 0% -0% -0% -0% -0% 0% 0% 0% 0% 0% 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. Source : NERA analysis 6

8 As a result, CfD assets are not risk-free even following construction Cash Flow risk, Individual Year NPV, Life of Asset Basis & Balancing Risk Basis & Balancing Risk Electricity Price Risk Electricity Price Risk Overall 5% VaR -0% -0% -0% -0% 0% 0% 0% 0% Cashflow in Individual Year Overall 5% VaR -0% -0% -0% 0% 0% 0% 0% NPV over Asset Life Figures show P5 / P95, downside / upside cases In single years, volume risk clearly dominates Over asset life, volume risk averages out Price-related risks remain under CfDs 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. Source : NERA analysis 7

9 Levy Control Framework (LCF) creates a significant risk that projects will not secure support 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

10 Risk of breaching LCF increases with lower wholesale power price, as CfD support requirement increases 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. Source : NERA analysis 9

11 Allocation of CFD support: implementation of auctions and detailed auction design allow government significant discretion Sample Profile of Incremental LCF Budget Expenditure Allocation of budget between technology groups is uncertain LCF Budget Year Less established: Offshore wind Biomass CHP Tidal/wave ACT AD Geothermal Established: Onshore wind Solar PV Hydro Landfill gas Sewage gas EfW CHP Government has discretion about allocation of funding to technology pots and ultimately between projects Projects seeking funding need to understand cost relative to other bidders in the merit order how clearing price could vary with auction year potential dependence of available budget on other market parameters (e.g. output, power prices) There may be opportunities for strategic bidding understanding when LCF looks tight and when it is less constrained 0

12 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 5, 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.

13 Thank you. Contact Daniel Radov Associate Director Energy & Environment London Dr. Mauricio Bermudez-Neubauer Associate Director, Energy & Environment London

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