Peak profit? The outlook for scarcity and peak prices in the GB … · 2020-02-26 · a 2 1. Context: Price volatility increased markedly in winter 2016/17, leading to an almost four-fold

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Peak profit? The outlook for scarcity and peak prices in the GB power market

24 November 2017

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1. Context: Price volatility increased markedly in winter 2016/17, leading to an

almost four-fold increase in energy market margins for peakers

2. Key drivers: 2016/17 saw a perfect storm of factors driving price spikes

above historical norms

3. Outlook: a return to 2016/17 prices is unlikely in the short term, but price

spread will increase in the long term due to the growth of renewables

Agenda

4. Investment: the persistence of peak prices will critically affect investment in

flexible technologies, as well as CM bidding strategies

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-50

0

50

100

150

200

250

Jan 11

Jan 17

Jan 13

Jan 09

Jan 07

Jan 15

Winter 2016/17 saw volatility and peak prices not seen since 2008

Source: Aurora Energy Research

1. Chart shows monthly percentiles. For example, the 99th percentile is the value that 99% of HH APX values were below for that month. 2. Volatility calculations take the logarithmical differences of daily average prices for consecutive trading days, and the relative standard deviation over a year, as per European Commission methodology.

▪ Winter 2016/17 saw wholesale prices spike to a maximum of £792/MWh, with the top percentile of prices reaching £243/MWh in November 2016

▪ Price volatility doubled in 2016/17 compared to 2014/15

APX price, monthly£/MWh

99th percentile reaches £243 in Nov 2016

1st99thMeanPercentiles1

Daily price volatility2

2008/09 159%

2016/17170%

2015/16106%

2014/1587%

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Higher peak prices in 2016/17 quadrupled gross margins of gas recips. and doubled that of CCGTs

Sources: Aurora Energy Research, Elexon

1. Analysis done by using an asset-dispatch model against historic prices. 2. Percentiles based all half-hour APX across the year, not just those where plant is running. Only considers potential revenues from energy trading between day-ahead, intra-day and balancing markets. Ramping costs excluded. 3. Representative gas recip with 39% HHV efficiency. 4. Representative high-merit CCGT with 54% HHV efficiency.

▪ Relative to the previous year, 2016/17 saw energy market profits increasing by ~300% for a gas recip. and nearly ~100% for a CCGT

▪ A gas recip participating in the day-ahead, intra-day and balancing markets could have made ~33% of its annual margins when power prices were above the 99th percentile in 2016/17

Energy market gross margins1, (£k/MW/year)

2015/16

+284%

2016/17

0-99th99th

2015/16

+96%

2016/17

Gas recip.3 CCGT4

Percentiles of spot price2

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Agenda



6CONFIDENTIAL: NOT FOR EXTERNAL DISTRIBUTION

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Winter 2016/17 saw a perfect storm of factors driving higher wholesale and system prices


1. Maximum aggregated MEL reported by coal plants in any period across a month.

SBR took 4GW of capacity out of the market1

Damaged French interconnector limited imports…. 3

Available capacity of interconnector to France, GW

Coal plants were not ready in autumn2

… whilst nuclear outages in France led to I/C exports4

Total contracted SBR capacity, MW

4,060

1,8742,025

14/15 16/1715/16

3

1

-1

0

2

Sep 17

Sep 15

Mar 17

Sep 16

Mar 16

Mar 15

Imports via France Interconnector, TWh

28 Sept 16: EDF announces 12 reactors offline

0

2

1

25-Nov

5-Dec

30-Nov

20-Nov

15-Nov

20 Nov 16: IFA I/C damaged

15

10

0

5

25

20

Sep 16

Jan 17

Nov 16

Jul 16

May 16

Mar 17

Jan 16

Mar 16

Coal weekly max MEL1, GW

Oct 16: 7 GW of coal available

Capacity

MEL

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Imperfect competition: the ability to price above marginal cost due to weak competition, portfolio concentration and/or information asymmetry

In addition to merit order effects, these factors increased components of ‘uplift’, pushing up market prices

Sources: Aurora Energy Research

Price,£/MWh

Electricity price

De

man

d

Uplift System Marginal Cost

Illustrative

1

2

3

4

Uplift

Marginal Cost

Opportunity cost: the trade off between selling in the wholesale versus balancing market

Imbalance cost: wholesale bids reflect the cost and risk of being out of balance in the BM

Ramping cost: the additional costs from increasing output to deliver at peak times

Instantaneous cost of operating: Fuel + CO2 + VOM + BSUoS + Embedded Benefits + Variable subsidies

Illustrative supply stack

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Ramping cost3SRMC2 Wholesale priceOther

Ramping cost

Ramping costs explain the majority of uplift on average, but contribute little to the very top prices


1. Analysis performed using historical APX prices between Oct 2016 – March 2017 inclusive, only considering periods where wholesale prices are greater than short-run marginal costs. 2. Short Run Marginal Cost 3. Ramping cost defined as the incremental cost to a system if an additional MW of generation is required. Proportion accrued towards ramping costs is based on “shadow price” analysis.

▪ In general, ramping costs explain 60% of total uplift in winter 2016/17

▪ However, this relationship breaks down in periods of high peak prices, as other factors dominate

▪ In the top 1 price periods in winter 2016/17, ramping costs accounted for less than 20% of total uplift

▪ Ramping costs were particularly high in the early part of Winter 2016/17 as coal plants were offline, whilst demand increased early in the season

1

Proportion of average wholesale price in winter 2016/171,%

All prices

Uplift

Uplift

Top 1 percentile of prices


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Generators must factor in the risk of high imbalance cost into their wholesale bids, driving up wholesale prices


▪ Generators must factor in the probability-weighted cost of imbalance into their EM pricing decisions

▪ On average, system short prices were ~£21/MWh higher in 2016/17

▪ During periods of high expected system prices, generators must factor in higher imbalance costs

▪ For instance, if generator expects to trip with 10% probability during top 1 percentile of system prices in 2016/17, an additional £29/MWh will be required in the EM

▪ The risk of tripping was higher for coal plants coming online from cold in Autumn 2016

0

10

20

30

40

50

60

70

80

5% 10% 15% 20% 25%

Imbalance costs2

Uplift required in EM,£/MWh

Probability of tripping/being short in EM

2015/16 (top 1% system short price)

2016/17 (avg system short price)

2015/16 (avg system short price)

2016/17 (top 1% system short price)


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Agenda



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7

CCGT/Biomass3Winter Review2

(June 2017)

Winter Outlook

(Oct 2017)

Embedded storage

CM will deliver a high margin in 2017/18; this could persist if NG and BEIS stick to current methodology


1. LOLE without SBR estimated to be 8.8 hours. 2. NG Winter Review estimated a de-rated margin of 3.7–4.9 GW. 3. Between the Winter Review and Winter outlook, NG revised the margin upwards by 1.3 GW due to lower embedded generation and more CCGTs/Biomass conversion staying on without CM contracts. Actual GWs estimated based on stated de-rated margins. 4. In its Electricity Capacity Report in 2016, NG recommends securing a total 64.4 GW de-rated capacity against ACS peak of 60.5 GW, based on the Cold Winter Base Case. 5. National Grid considers over 20 scenarios, indicating the total de-rated capacity in each to meet the 3 hours LOLE reliability standard. A “Least Worst Regret (LWR)” tool is then used to calculate the appropriate level of capacity to secure to meet the Reliability Standard that minimises regret costs of that decision.

▪ In 2016/17, NG estimated de-rated margin without SBR to be 1.1%, with 8.8 hours LoLE

▪ With CM in place in 2017/18, the margin is expected to be higher, with LoLE of only 0.01 hours -significantly lower than the reliability standard of 3 hours. This is due to two main factors: – NG’s methodology

assumes downside scenario, hence over-procures capacity needed to hit 3 hours LoLE in Base Case5

– Additional capacity operating without CM contract

De-rated marginGW

0.05LOLEHours

0.01

NG recommended4

NG base

Winter Outlook

(Oct 2016)

0.51

SB

R

Winter 2016/17


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Net imbalance volumes (NIV) and balancing costs are expected to rise with growth of intermittent renewables

Sources: Aurora Energy Research, Elexon

Net Imbalance Volume (NIV)Half-hourly, MWh

20302020

▪ Long and short imbalance is expected to increase in the period to 2040

▪ NIV is expected to become more symmetric, but with a moderate leaning to being long due to asymmetric penalty prices

▪ Deployment of flexible capacity is unable to fully offset the higher levels of imbalance resulting from greater intermittent renewables penetration

Percentage of time in year

50% 100%0%

Lo

ng

Sh

ort

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Overall a return to 2016/17 peak prices is unlikely in the short term, but we expect price spread to increase in the long term


Yearly wholesale prices£/MWh

2025 2040203520302015 2020

99%1%

Percentiles

▪ Winter 2016/17 saw a perfect storm of factors leading to a surge in peak prices

▪ Prices have now returned to pre-2016 norms

▪ In the short to medium term, a return to 2016/17 pricing is unlikely (under normal market conditions)

▪ We expect the price spread to increase through the 2020s, principally driven by the growth in renewables

Historic

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Agenda




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Discount rates for peakers need to reflect the risks associated with reliance on peak prices


1. Both BM and EM revenues considered. Discount factor of 6% applied to Capacity Market revenue and costs, 11% applied to remaining margin. Project lifetime of 20 years for gas recip. and, 13 years for batteries, starting from 2021. 2. Percentiles based on all half-hour APX across the year, not just those where plant is running. 3. Other includes Capacity Market contracts and embedded benefits. 4. Gas reciprocating engine with 38% efficiency. 5. Lithium Ion battery with 1 hour storage operating at 85% efficiency and an arbitrage business model.

Gross Margin

Cost

PV of new-build in 20211,£/kW

NPV,£/kW

10% 15% 20% 25% 30%CostGross

Margin

Gas recip Battery

A generic gas recip. is expected to derive 24% of future discounted margins from the top 1 percentile of prices (20% for a battery)

A typical battery project (built in 2021) becomes unviable if revenues from the top 1 percentile of prices are discounted at over 20%

Discount rate for 99-100 percentile prices

Battery

Gas Recip.0-9999-100

FOMOther3 CAPEX

Percentile of spot price2

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Key Takeaways


Peak prices are the key uncertainty for investment in thermal assets: higher peak prices in 2016/17 quadrupled gross margins of gas recips. and doubled that of CCGTs, relative to the previous year

Winter 2016/17 saw power prices peak to levels not seen since 2008, with the wholesale price hitting £792/MWh and system prices reaching £1,500/MWh

Whilst we expect price volatility to increase in the long term due to the growth of renewables, a return to 2016/17 peak prices is unlikely in the short term

Investors need to properly consider the risks associated with reliance on peak prices: a typical peaker derives nearly a quarter of its gross margins from the top 1% of prices

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Peak profit? The outlook for scarcity and peak prices in the GB … · 2020-02-26 · a 2 1. Context: Price volatility increased markedly in winter 2016/17, leading to an almost four-fold