Assumptions on Costs and Scenarios BERLIN,

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1 Cost optimal expansion of renewables in Germany Assumptions on Costs and Scenarios BERLIN,

2 Assumptions on future investment costs per technology Assumptions on the investment cost of renewables are based on the lead study of the German ministry of environment 1 and were updated to recent market trends Investment Cost, EUR/kW peak BMU Leitstudie Adjustment of future cost development based on market trends 2 Assumptions used: Year PV rooftop years earlier PV ground-mounted Wind onshore (low-wind sites) Wind onshore (strong wind sites) Wind offshore (excl. offshore-grid) year delay Adjustments by Agora Energiewende; main sources used: PV: Photon Pricemonitor Solar plants, Fraunhofer ISE study on power generation costs ( studie-stromgestehungskosten-erneuerbare-energien.pdf); offshore wind: Crown Estate Pathways Studie Offshore%20wind%20cost%20reduction%20pathways%20study.pdf); onshore wind: expert discussions, published costs od wind farms 2

3 Detailed description of renewable expansion paths 3

4 Two different expansion paths and an additional sensitivity are analysed, Reference Scenario Leading thought in Scenario design RES Expansion path 1 RES Expansion path 2 Sensitivity PV More wind onshore, distributed all actross Germany More PV, distributed all across Germany Strong reduction in wind offshore Local distribution on distribution-grid-level is optimized More wind onshore in the north Less PV in the north, limit at 52 GW Reduction in wind offshore Local distribution on distribution-grid-level is not optimized Expansion similar to expansion path 1, in addition a drastic expansion of PV + Battery systems Focus is NOT on cost of RES generation but on indirect effects on the power system Expansion of RES focuses more on consumption Expansion of RES focuses more on best natural ressources Breakthrough of PV+Battery systems leads to uncontrolled expansion 4

5 Installed capacities of RES technologies in the scenarios Installed capacities (in GW) in all scenarios lead to power generation of wind and PV of 244 TWh in 2023 and 366 TWh in 2033 Changes per technologie in comparison to reference Scenario/ German Grid Development Plan (in 2023, 2033) Installed Capacity in 2023/in 2033 Reference Scenario Ausbaupfad 1 keine More wind onshore, mostly in the south (+14, +23 GW) Some more PV, distributed across all Germany (+2, + 8 GW) A lot less wind offshore (-9, -16 GW) Wind onshore: 49/66 GW PV: 61/ 65 GW Wind offshore: 14/25 GW Wind onshore: 64/89 GW PV: 63/73 GW Wind offshore: 5/9 GW Ausbaupfad 2 More wind onshore in the north (+12, + 19 GW) Less PV in the north (-9, -13 GW) Less wind offshore (-7, - 12 GW) Wind onshore: 61/85 GW PV: 52/ 52 GW Wind offshore: 7/14 GW PV Breakthrough Etwas mehr PV (+ 5, + 11 GW, identisch mit Ausbaupfad 1) Viel mehr Systeme aus PV+Batterie (+19, +74 GW ) In 2023 etwas mehr Wind onshore (-8GW) In 2033 weniger Wind offshore (-18 GW) PV: 85/150 GW, davon 19/74 GW mit Batterie Wind onshore: 57/66 GW Wind offshore: 5/7 GW 5

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8 Installed Capacity (in GW) per technology For comparison only: old scenarios of German Grid Development Plan 2012: NEP2012-B is the lead scenario for 2022 NEP2012-C is the high-renewable scenario (only defined up to 2022) GW Installed capacity, 2023 GW Installed capacity, Wind onshore Wind offshore PV Wind onshore Wind offshore PV NEP2012-B NEP2012-C Basisszenario Reference- (NEP Scenario 2013 B) "beste Resource-driven Standorte" "verbrauchsnahe Consumptiondriven Erzeugung" "PV breakthrough" 8

9 Generation per technology (in TWh) For comparison only: old scenarios of German Grid Development Plan 2012: NEP2012-B is the lead scenario for 2022 NEP2012-C is the high-renewable scenario (only defined up to 2022) TWh Generation, 2023 TWh Generation, NEP2012-B Wind onshore Wind offshore PV Wind onshore Strong increase of generation of wind onshore due to updated assumptions on wind turbine design compared to those of the German Grid Development Plan (assumptions of 2008 were used there) Wind offshore PV NEP2012-C (Werte 2023 Basisszenario Reference- (NEP Scenario 2013 B) "beste Resource-driven Standorte" "verbrauchsnahe Consumptiondriven Erzeugung" 9

10 Wind onshore: Installed capacities per state of Germany (Bundesländer), in GW GW C2023 Basisszenario Reference- Scenario (NEP 2013 B) "verbrauchsnahe Consumption-driven Erzeugung" "beste Resource-driven Standorte" States with additional wind onshore in consumption-driven scenario States with additional wind onshore in ressource-driven scenario 10

11 Scenario Definition Wind onshore 2033: Installed Capacity per Transmission Grid Node, in GW Distribution of wind onshore in reference scenario (66 GW in 2033) Distribution of wind onshore in Distribution of wind onshore in consumption-driven ressource-driven (89 GW in 2033) (85 GW in 2033) Basiszenario Reference Illustration based on grid nodes, not to scale Zusätzlicher Ausbau Additional expansion 11

12 Photovoltaic: Installed capacities per state of Germany (Bundesländer), in GW GW C2023 Basiszenario Reference- Scenario (NEP2013 B) "verbrauchsnahe Consumption-driven Erzeugung" "beste Resource-driven Standorte" States with additional PV in consumption-driven scenario States without reduction of PV in ressource-driven scenario in

13 Scenario Definition PV 2033: Installed Capacity per Transmission Grid Node, in GW Distribution of PV, reference scenario (65 GW in 2033) Distribution of PV, consumption-driven (73 GW in 2033) Reference Basiszenario Illustration based on grid nodes, not to scale Distribution of PV, ressource-driven (52 GW in 2033) Additional expansion Zusätzlicher Ausbau 13

14 Detailed analysis of updated investment cost of renewable energies 14

15 Assumptions are based on the lead study of the German ministry of environmen and were updated where necessary BMU lead study includes investment costs per renewable technologies in EUR/kWpeak, PV and Wind Offshore: Update to recent market developments, based on credible reports of industry: Cost degression PV: 5 years faster than expected Cost degression Wind offshore: 3 years later than expected Wind onshore: Different cost assumptions for turbines in high- and low-windspeed locations, based on published data, own analysis and expert interviews 15

16 PV 16

17 Investment Cost for PV are based on BMU lead study, cost degression is advanced by 5 years Investment cost, EUR/kWpeak Annahmen BMU Leitstudie Reale Werte 2012 (basierend auf Photon Preismonitor) Gewählte Annahmen: PV Gesamt Quellen: Photon Preismonitor,

18 Differences for rooftop and ground mounted PV installations are considered 1800 Investment cost, EUR/kWpeak Gewählte Annahmen: PV Gesamt Gewählte Annahmen: Aufdachanlagen Gewählte Annahmen: Freiflächen Quellen:

19 Investment cost for small PV installations are monitored transparently, assumptions for larger installations are based on analysis of Fraunhofer ISE Photon Preismonitor Based on Photon price monitoring Investment cost, EUR/kWpeak Gleiches Kostenverhältnis Same cost ration as in Groß- und Kleinanlagen wie analysis of ISE in ISE-Studie ISE-Studie zu Kosten EE Quellen: Photon Preismonitor,

20 Backup Regional differences in generation profile are simulated in detail based on the weather year

21 Wind offshore 21

22 Investment Cost for wind offshore are based on BMU lead study, cost degression is delayed by 3 years Investment cost, EUR/kWpeak Annahmen BMU Leitstudie Real abgeschlossene Verträge für 2013 (Stand Mai 2012) 4500 Gewählte Annahmen: Wind Offshore (exkl. Netzanbindung) Quellen:

23 Additional cost for offshore grids to connect offshore wind are considered Investment cost, EUR/kWpeak Gewählte Annahmen: Wind Offshore (exkl. Netzanbindung) Gewählte Annahmen: Wind Offshore (inkl. Netzanbindung) Quellen:

24 Source of assumption for Wind offshore: Analysis of The Crown Estate and own analysis for German wind parts (red) Kosten für Alpha Ventus: ~4,7 MioEUR/MW Kosten für Baltic 1: ~4,6-6,7 MioEUR/MW Kosten für Bard Offshore : ~7,3 MioEUR/MW Kosten für Nordsee Ost: ~3,9 MioEUR/MW Quellen: Anpassungen entsprechend der Annahmen der Studie: Wechselkurs GBP/EUR (+17%), Abzug der Kosten für Netzanbindung (-15%) Quellen Deutsche Windparks:

25 Wind onshore 25

26 Different wind turbine configurations are assumed for sites with low- and high windspeed, differences in cost are considered Assumptions on configuration for different sites (IWES) 2013 high windspeed low windspeed Rated power(mw) 2,5 2,2 Hub height (m) Rotor diameter (m) high windspeed low windspeed Rated power(mw) 3 3 Hub height (m) Rotor diameter (m) high windspeed low windspeed Rated power(mw) 4,5 4 Hub height (m) Rotor diameter (m) Estimation of additional investment cost for wind turbines in sites with low-windspeeds: Development of a cost-driver-model Calibration of model by published data of real costs Expert discussions (manufacturer, project developer, academia) Assumption by IWES: Wind turbines for low windspeeds are built in sites with average windspeeds of 7,5 m/s or below (at hub hiehgt) 26

27 Different investment cost for wind turbines for sites with low- and high windspeeds Investment cost, EUR/kWpeak Annahmen BMU lead BMU study Leitstudie = Annahmen Kosten Windausbau im Basisszenario Gewählte High-windspeeds Annahmen: Starkwindanlagen Differences in configuration between low windspeed and high windspeed wind turbines are larger in 2013 and 2033 and smaller in 2023, cost difference in 2023 is therefore lower compared to 2013 and 2033 Gewählte low-windspeeds Annahmen: Schwachwindanlagen Quellen: eigene Analyse zu Kostenverhältnis high windspeed und low windspeedanlagen 27

28 Starting point for estimations: Analysis by IRENA on cost components of wind turbines Direkte Anlagenkosten für Turm, Rotor, Generator, Gondel etc. werden durch unterschiedliche Auslegung beeinflusst Investitionsnebenkosten (Planung und Projektierung, Netzanschluss etc.) werden nicht wesentlich durch Unterschiede in Hub height und Rotor diameter beeinflusst Investitionsnebenkosten machen 20-30% der gesamten Kosten aus Quelle: Nebenkosten:

29 Abschätzung der relativen Investitionskosten auf Basis eines Kostentreibermodells (high windspeed/low windspeed) (1/2) Schritt 1: Aufteilung der Gesamtkosten auf Komponenten (IRENA): Welche Komponente verursacht wie viel % der direkten Investitionskosten? 5 Schritte zur Ermittlung der relativen Kosten für low windspeedanlagen und high windspeedanlagen : 1. Aufteilung der Investitionskosten auf Komponenten (nach IRENA) 2. Zuordnung der Kosten je Komponente auf Kostentreiber (eigene Zuordnung) 3. Annahmen zur Auswirkungen von 10% Erhöhung des Kostentreibers auf betroffene Komponenten 4. Berechnung der relativen Morekosten je low windspeedanlage 5. Berechnung der spezifischen Investitionskosten (je MW) To be translated Schritt 2. Zuordnung auf wesentliche Kostentreiber: "durch welchen der drei Treiber (Nennleistung, Rotor diameter, Hub height) steigen die Kosten der jeweiligen Komponente?" Komponente Anteil an Kosten Nenn- Leistung Rotordurchmesser Hub height Tower 26% 0,1 0,1 0,8 Rotor Blades 22% 1,0 Rotor Hub 1% 1,0 Rotor Bearings 1% 1,0 Main Shaft 2% 1,0 Main Frame 3% 1,0 Gearbox 13% 1,0 Generator 3% 1,0 Yaw System 1% 1,0 Pitch System 3% 1,0 Power Converter 5% 1,0 Transformer 4% 1,0 Brake System 1% 1,0 Nacelle housing 1% 1,0 Ergebnis Schritt 1+2: Cables 1% 1,0 Welcher Anteil der Gesamtkosten Screws 1% 1,0 wird von welchem Other (fehlend zu 100%) 11% 1,0 Kostentreiber beeinflusst? Gesamt 100% 54% 25% 21% Quelle: 29

30 Abschätzung der relativen Investitionskosten auf Basis eines Kostentreibermodells (high windspeed/low windspeed) (1/2) To be translated Schritt 3: Annahmen zur Auswirkungen von X% Erhöhung des Kostentreibers auf betroffene Komponenten: Um wie viel erhöhen sich die betroffenen Komponenten bei einer Erhöhung z.b. der Turmhöhe um 10%? Rel. Auswirkung des Kostentreibers Leistung 1,0 Rotor diameter 2,0 Hub height 2,0 Erklärung: "1" bedeutet bei einem 10% höheren Turm kosten die betreffenden Komponenten 10% More, "2" bedeutet: bei 10% höherem Turm kosten die betreffenden Komponenten 20% More Schritt 4: Berechnung der Morekosten je low windspeedanlage (unter Benutzung der Annahmen aus Schritt 1-3): Um wie viel % verändern die unterstellten Änderungen in den Kostentreibern die relativen Kosten der betroffenen Komponenten? Annahmen (IWES) Berechnung high windspeedanlage low windspeedanlage Leistung (MW) 3,0 3,0 Rotor diameter (m) Hub height (m) Der Rotor diameter ist um 15% größer die Kosten der Komponenten, die durch den Kostentreiber Rotor diameter beeinflusst werden (25% der Gesamtkosten), steigen um 30% Die Turmhöhe ist um 27% höher die Kosten der Komponenten, die durch den Kostentreiber Turmhöhe beeinflusst werden (21% der Gesamtkosten), steigen um 54% 30

31 Resulting assumptions for cost of different wind turbine configurations 2013 high windspeed low windspeed Rated power(mw) 2,5 2,2 Hub height (m) Rotor diameter (m) Annahmen der Schritte 1-3 Additional cost for low-windspeed configuration per MW 22% Additional cost for low-windspeed configuration excluding indirect cost per MW 26% 2023 high windspeed low windspeed Rated power(mw) 3 3 Hub height (m) Rotor diameter (m) % 19% 2033 high windspeed low windspeed Rated power(mw) 4,5 4 Hub height (m) Rotor diameter (m) % 24% 31

32 Backup Regional Differences in Generation of Wind Turbines were considered in detail based on weather year Szenarioramen NEP