GB Wholesale Market Summary March 2021

Published April 2021 1. A combination of higher carbon prices and demand caused the monthly average power price in E x e c u t i v e March 2021 to rise to £54.1/MWh, a £1.2/MWh (2.3%) increase from February 2021. This represents a year-on-year increase of £25.63/MWh (89.9%) due to a subsequent economic recovery from the initial crash caused by COVID-19. See slides 5, 6, and 7. S u m m a r y 2. Power prices in March saw high levels of volatility with several negative periods and prices exceeding £280/MWh. This was primarily driven by weather intermittency coupled with higher demand. See slides 5 and 8. 3. Driven by increased economic activity from relaxation of the national lockdown, the monthly transmission power demand in March increased by 0.8 TWh (3.6%) relative to February, while the share of low carbon generation fell by 7 p.p. to 56.2% of total generation. See slides 10 and 11. 4. Monthly thermal generation in March increased by 1.5 TWh (19.2%) relative to February as demand increased, and renewables output decreased. Consequently, carbon emissions increased

by 0.5 MtCO2e (13.3%) compared to February. See slides 11 and 14. 5. The profitability of wind assets in March saw a decrease relative to February, caused by an 11 p.p. decrease in wind load factors to a monthly average of 40.5%. This was accompanied by a decrease in wind capture prices (£1.2/MWh or 2.4% relative to February). See slides 20 and 22.

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Source: Aurora Energy Research 3 Agenda

I. System performance

II. Company performance (available to subscribers only)

III. Plant performance

4 1 System performance Half-hourly EPEX spot price for March

1 EPEX spot price Monthly average price in March 2021: £/MWh £54.14/MWh 300

270

240

210

180

150

120

-30 01-Mar 08-Mar 15-Mar 22-Mar 29-Mar

1) Half-hourly EPEX is the volume-weighted reference price over that half-hour interval, as provided by EPEX Spot

Sources: Aurora Energy Research, Thomson Reuters 5 1 System performance Historic monthly average EPEX spot price

Average EPEX spot price1, £/MWh

60 +2.3% 55

40 +89.9%

20 Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- 10 11 12 13 14 15 16 17 18 19 20 21

Average monthly spot price Annual average spot price x Month-on-month difference x Year-on-year difference 1) Average monthly EPEX is the average over the month of the volume-weighted reference prices for each half-hour interval.

Sources: Aurora Energy Research, Thomson Reuters 6 1 System performance Historic fuel prices Gas, Coal and Carbon daily prices

Gas/Coal price Total carbon price1

£/MWh £/tCO2 30 60

25 50

20 40

15 30

10 20

5 10

0 0 Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov Dec- Jan- Feb- Mar- 20 20 20 20 20 20 20 20 20 20 21 21 21

Gas Coal Carbon 1) Includes EU-ETS and CPS. The UK left the EU-ETS scheme in 2021 to a national UK-ETS scheme

Sources: Aurora Energy Research, Thomson Reuters 7 1 System performance Half-hourly spot prices against half-hourly system margins for March

EPEX spot price1, £/MWh

300 280 260 240 220 200 180 160 140 120 100 80 60 40 20 0 -20 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Margins2, MW

1) Half-hourly EPEX is the volume-weighted reference price over that half-hour interval, as provided by EPEX Spot. 2) Margins are calculated as the difference between MEL and Demand for each half-hour period. Demand data presented here is Initial Transmission System Demand Out-Turn, and does not include embedded demand. MEL is calculated as the sum of all transmission BM units reporting MEL values in each half-hour. Where a BMU gives multiple values in a half-hour, only the least is taken. Sources: Elexon, National Grid, Thomson Reuters, Aurora Energy Research 8 1 System performance Daily March max and min demand Relative to historic March max and min demand since 20101

Demand2, GW

0 M Tu W Th F Sa Su M Tu W Th F Sa Su M Tu W Th F Sa Su M Tu W Th F Sa Su M Tu W

Daily range Historic maximum/minimum 1) Data from previous years is matched to the nearest weekday within the current month, to maintain the weekly demand pattern. 2) Demand data presented here is Initial Transmission System Demand Out-Turn, and does not include embedded demand.

Sources: National Grid, Aurora Energy Research 9 1 System performance Monthly historical demand on the transmission system

Total demand1, TWh

24 +3.6%

22 +0.4%

16 Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- 10 11 12 13 14 15 16 17 18 19 20 21

Total monthly demand Annual average demand x Month-on-month difference x Year-on-year difference 1) Demand data presented here is Initial Transmission System Demand Out-Turn, and includes station transformer load, pumped storage demand and interconnector demand, but does not include embedded demand.

Sources: National Grid, Aurora Energy Research 10 1 System performance Monthly fuel mix breakdown

Output1 TWh

22 0.9 0.3 21.0 1.8 1% 20 4% 1.8 8% 18 2.3 8% 16 3.3 11% 14 12 16% 3.5 100% 10 16% 8 7.2 6

4 34% 2 0 CCGT Nuclear Offshore Wind Other Onshore Wind2 Other fossil3 Solar Coal Total renewables Load factor, % 36 49 45 59 36 31 9 7

1) Includes outputs from generators registered as BM Units as well as embedded wind and solar PV assets. All numbers are rounded to 0.1 TWh which means that subtotals may not sum to total value. 2) Other fossil includes oil, CHP-CCGT and OCGT. 3) Other renewables includes biomass and hydro. Sources: Elexon, Sheffield Solar, National Grid, Aurora Energy Research 11 1 System performance Historical fuel mix breakdown

Output1 % of total

100% 4% 0% 1% 1% 6% 6% 5% 8% 0% 8% 9% 90% 6% 5% 14% 4% 18% 16% 5% 9% 10% 80% 5% 6% 19% 8% 29% 7% 5% 21% 6% 15% 8% 70% 44% 18% 8% 7% 15% 11% 17% 8% 60% 34% 9% 8% 9% 31% 50% 9% 36% 51% 46% 40% 39% 41% 35% 26% 28% 34% 18% 26% 30% 15% 6% 20% 2% 2% 1% 10% 20% 23% 20% 20% 21% 23% 21% 19% 19% 19% 16% 16% 0% Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- Mar- 10 11 12 13 14 15 16 17 18 19 20 21

Nuclear Coal CCGT Other fossil2 Other renewables3 Onshore Wind Offshore Wind Solar 1) Includes outputs from generators registered as BM Units as well as embedded wind and solar PV. 2) Other fossil includes oil, CHP-CCGT and OCGT. 3) Other renewables includes biomass and hydro.

Sources: Elexon, Sheffield Solar, National Grid, Aurora Energy Research 12 1 System performance Monthly interconnector flow duration curve Flow in each half-hour for GB interconnectors

Flow1, MW

2,500

2,000

1,500

1,000

500

-500

-1,000

-1,500

-2,000

Time Half-hours I/C France I/C Netherlands I/C N. Ireland I/C Rep. Ireland I/C Belgium 1) Positive flow is imports into GB, negative flow is exports.

Sources: Elexon, National Grid, Aurora Energy Research 13 1 System performance Monthly power sector emissions by technology

Emissions1 Carbon intensity

MtCO2e gCO2e/kWh 7 280 +18.1% 6 5.8 +13.3% 240

5 4.6 200 4.2 3.9 4 3.8 3.8 3.7 3.7 160 3.6 3.4

3 2.9 120 2.4 2.1 2 80

1 40

0 0 Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan- Feb- Mar- 20 20 20 20 20 20 20 20 20 20 21 21 21

Biomass Other fossil2 CCGT Coal System carbon intensity x Month-on-month emissions difference x Year-on-year carbon intensity difference 1) Please refer to Appendix for details of methodology employed to calculate emission amounts. Includes all Balancing Mechanism plants. 2) Other fossil includes oil, OCGT and gas CHP-CCGT.

Sources: Elexon, Ofgem, Aurora Energy Research 14 Agenda

I. System performance

II. Company performance (available to subscribers only)

III. Plant performance

15 Agenda

I. System performance

II. Company performance (available to subscribers only)

III. Plant performance

16 3 Plant Performance Plant utilisation – load factors by plant

Load factor1 Column width % reflects capacity

100

40 Ø 36 30

-10 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 Capacity, GW Biomass Coal Hydro Nuclear Offshore Wind Onshore Wind Solar CCGT Gas CHP-CCGT Interconnector OCGT Oil Pumped Storage 1) Represents 60 plants with highest capacity according to the Balancing Mechanism (BM) database, as well as aggregated data for wind and solar. Capacity of each plant represents the sum of capacities of all its generators that have been active at least once in the last three months. Please refer to Appendix for a detailed description of the data used and categories presented Sources: Aurora Energy Research, Elexon, BEIS 17 3 Plant Performance CCGT plant utilisation – by plant

Full load hours1 Column width % of total for the period reflects capacity

100

80 76.6

65.7 62.5

60 58.1

55.4

53.6

52.4

51.6 47.7

50 47.6 45.7

40 40.3 29.7

30 29.5

25.5

25.4

23.3

14.0

20.5

19.6

18.3 18.2

20 14.4

10.5

0.0 0.0

10 0.0

1.7

0.0 0.0 0.0 0.0 0 0.0 0 5 10 15 20 25 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 24 25 27 31 32 33 23 26 28 30 Calon Centrica Drax EDF EPH ESB Intergen Munich Re RWE SSE Uniper 29 Capacity, Plant Names: 1. South Humber Bank, 2. Pembroke, 3. Marchwood, 4. Carrington, 5. Staythorpe, 6. Cottam Dvpt Centre, 7. Peterhead, 8. Spalding, 9. Kings Lynn, 10. Didcot B, 11. Great Yarmouth, 12. Little Barford, 13. GW Rocksavage, 14. Seabank 1, 15. Keadby, 16. Coryton, 17. Medway, 18. Connahs Quay, 19. West Burton B, 20. Damhead Creek, 21. Langage, 22. Shoreham, 23. Seabank 2, 24. Rye House, 25. Killingholme 2, 26. Killingholme 1, 27. Sutton Bridge, 28. Glanford Brigg, 29. Enfield Energy, 30. Peterborough, 31. Corby, 32. Severn, 33. Baglan Bay. 1) Includes all CCGT plants of the presented companies that report to the Balancing Mechanism

Sources: Aurora Energy Research, Elexon 18 3 Plant performance Coal plant utilisation – by plant

Full load hours1 Column width % of total for the period reflects capacity

100

20 13.3 10 4.8 3.1 0.0 0 0 2 4 6 1 2 3 4 Capacity, Drax EDF SIMEC Uniper GW

Plant Names: 1. Ratcliffe, 2. Drax Coal, 3. West Burton, 4. Uskmouth

1) Includes all coal plants of the presented companies that report to the Balancing Mechanism

Sources: Aurora Energy Research, Elexon 19 3 Plant performance Monthly load factors by technology

Average load factor1 %

43 20 35 34 32 36 24 23 22 23 21 28 28 26 0 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21 60

40 54 56 52 52 59 20 41 48 45 34 31 36 34 36 0 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21 30

10 17 20 12 16 15 13 12 6 6 9 0 4 2 3 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21

Onshore Wind Onshore Average Offshore Wind Offshore Average Solar Solar Average 1) Includes outputs from generators registered as BM Units as well as embedded wind and solar PV

Sources: Aurora Energy Research, Elexon, Crown Estate 20 3 Plant performance Wind farm utilisation – load factor by wind farm

Load factor1 %

100 90 80 70 60 50 40 30 20 10 0 1 10 20 30 40 50 60 70 80 90 100 107 109 108 Offshore Wind Onshore Wind

Plant Names: 1. Halsary Windfarm, 2. Whiteside Hill, 3. Gordonstown, 4. Hywind Scotland, 5. Aikengall 2, 6. Dorenell, 7. Fallago Rig, 8. Sanquhar Community, 9. Corriegarth, 10. Crystal Rig, 11. Brockloch Rig 2, 12. Coire Na Cloiche, 13. Hornsea 1 , 14. Beatrice, 15. Westermost Rough, 16. Farr, 17. Millennium, 18. Blackcraig, 19. Auchrobert, 20. Kilbraur, 21. Rothes Extension, 22. Humber, 23. Stronelairg, 24. East Anglia One, 25. Galawhistle, 26. Dudgeon, 27. Cour, 28. Hill of Glaschyle, 29. Race Bank, 30. Beinneun, 31. Walney, 32. Andershaw, 33. Kilgallioch, 34. Sheringham Shoals, 35. Galloper, 36. Carraig Gheal, 37. West of Duddon Sands, 38. Burbo Extension, 39. London Array, 40. Lincs, 41. Gwynt y Mor, 42. Dunmaglass, 43. Bad a Cheo, 44. Minsca, 45. Walney Extension, 46. Baillie, 47. Greater Gabbard, 48. Assel Valley, 49. Aberdeen, 50. Mid Hill, 51. Bhlaraidh, 52. Strathy North, 53. Beinn Tharsuinn, 54. Camster, 55. Burbo Bank, 56. Berry Burn, 57. Clyde, 58. Afton, 59. Rampion, 60. Robin Rigg, 61. Dalswinton, 62. Kype Muir, 63. Corriemoillie, 64. Barrow, 65. Harburnhead, 66. Toddleburn, 67. Ormonde, 68. Lochluichart, 69. Freasdail, 70. Gunfleet Sands, 71. Gordonbush, 72. Tullymurdoch, 73. Hare Hill Extension, 74. Ewe Hill, 75. Pen y Cymoedd, 76. Thanet, 77. Griffin, 78. Burn of Whilk, 79. Braes of Doune, 80. Glen App, 81. Minnygap, 82. Beinn An Tuirc , 83. Glens of Foudland, 84. Clashindarroch, 85. Dersalloch, 86. An Suidhe, 87. Arecleoch, 88. Whitelee, 89. Hill of Towie, 90. Edinbane, 91. Tullo, 92. Goole Fields, 93. Tullo Extension, 94. Dun Law Extension, 95. Black Law, 96. Harestanes, 97. A Chruach, 98. Moy, 99. Mark Hill, 100. Hadyard Hill, 101. Craig, 102. Glenchamber, 103. Clachan Flats, 104. Airies, 105. Embedded Wind, 106. Brownieleys, 107. Keith Hill, 108. Kincardine, 109. Middle Muir.

1) Represents UK wind farms reporting Balancing Mechanism Unit data. Figures presented reflect Final Physical Notification (FPN) expectations reported to the grid, which are not always representative of actual production

Sources: Aurora Energy Research, Elexon, Crown Estate 21 3 Plant performance Wind capture price versus baseload price

Price £/MWh

60 -2.4%

0 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21 Wind load factors %

35 24 23 22 23 21 28 28 34 32 26 43 36

54 34 31 36 34 36 41 56 52 52 48 59 45 Baseload1 Wind Capture 2 1) Baseload price is the average monthly EPEX price; 2) Wind capture price is the load-weighted monthly average EPEX price across all wind Balancing Mechanism plants for all half-hourly periods

Sources: Aurora Energy Research, Elexon, Thomson Reuters 22 Appendix

Data used

▪ Output values used in this summary reflect the sum of Final Physical Notifications (FPN) submitted by all BM Units of a given plant that have been active over the last three months. ▪ Capacity values used in this summary reflect the sum of capacities of individual BM Units, as reported to the Balancing Mechanism, that have been active over the last three months. They reflect long-term capacities and exclude temporary fluctuations due e.g. to plant failures or scheduled maintenance. ▪ Prices used in this summary are the EPEX half-hourly Reference Prices for half-hourly, two-hourly and four-hourly spot products.

Categories presented

▪ Full-load hours represent the plants’ load factors, calculated as the ratio of the output produced in a given month to the maximum possible output given the plants’ capacity. ▪ Running hours represent the proportion of time in a given month when a plant has been active, i.e. when at least one of its BM Units produced output greater than zero. ▪ Capture prices (or average output-weighted prices) are calculated as an average of EPEX half-hourly prices per MWh weighted by the plants’ corresponding half-hourly outputs for all periods. ▪ Average gross margins are calculated as a sum of the uplift and inframarginal rent. Uplift is calculated as the difference between the EPEX price and the system marginal cost (SMC). SMC is the maximum marginal cost of all the plants with at least one generator producing above 80% of its installed capacity in a given half-hour. ▪ Emissions are calculated as plant output divided by electrical efficiency, multiplied by theoretical carbon content of the fuel input. The carbon content of fuel inputs is sourced from BEIS’s Greenhouse gas reporting – Conversion factors 2016. System carbon intensity is calculated as the total emission divided by total electricity generated.

Source: Aurora Energy Research 23 Disclaimer and Copyright

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