Backup Disclaimer (I/II)

This document and the presentation to which it relates contains information relating to E.ON SE ("E.ON") that must not be relied upon for any purpose and may not be redistributed, reproduced, published, or passed on to any other person or used in whole or in part for any other purpose. By accessing this document you agree to abide by the limitations set out in this document. This document is being presented solely for informational purposes and should not be treated as giving investment advice. The information contained in this presentation comprise financial and similar information (e.g. pro-forma financial results). This information is neither audited nor reviewed and should be considered preliminary and subject to change. In particular the presentation of pro-forma financial results may be different compared to the final presentation within the E.ON consolidated financial statements. Certain information in this presentation is based on management estimates. Such estimates have been made in good faith and represent the current beliefs of applicable members of management. Estimates may not be correct or complete. Accordingly, no representation or warranty (express or implied) is given that such estimates are correct or complete. We advise you that some of the information presented herein is based on statements by third parties, and that no representation or warranty, express or implied, is made as to, and no reliance should be placed on, the fairness, accuracy, completeness or correctness of this information or any other information or opinions contained herein, for any purpose whatsoever. Certain statements contained herein may be statements of future expectations and other forward-looking statements that are based on the E.ON’s current views and assumptions and involve known and unknown risks and uncertainties that may cause actual results, performance or events to differ materially from those expressed or implied in such statements. No one undertakes to publicly update or revise any such forward-looking statement. Neither E.ON or any of their respective officers, employees or affiliates nor any other person shall assume or accept any responsibility, obligation or liability whatsoever (in negligence or otherwise) for any loss howsoever arising from any use of this presentation or the statements contained herein as to third person statements, any statements of future expectations and other forward-looking statements, or the fairness, accuracy, completeness or correctness of statements contained herein. In giving this presentation, none of E.ON or their respective agents undertake any obligation to provide the recipient with access to any additional information or to update this presentation or any information or to correct any inaccuracies in any such information. Disclaimer (II/II)

This presentation is not intended to provide the basis for any evaluation or any securities and should not be considered as a recommendation that any person should purchase any shares or other securities. This presentation contains certain financial measures (including forward-looking measures) that are not calculated in accordance with IFRS and are therefore considered as "Non-IFRS financial measures". The Management of E.ON believes that the Non-IFRS financial measures used by E.ON, when considered in conjunction with (but not in lieu of) other measures that are computed in accordance with IFRS, enhance an understanding of EON's results of operations, financial position or cash flows. A number of these Non-IFRS financial measures are also commonly used by securities analysts, credit rating agencies and investors to evaluate and compare the periodic and future operating performance and value of E.ON and other companies with which E.ON competes. These Non-IFRS financial measures should not be considered in isolation as a measure of E.ON's profitability or liquidity, and should be considered in addition to, rather than as a substitute for, net income and the other income or cash flow data prepared in accordance with IFRS. In particular, there are material limitations associated with our use of Non- IFRS financial measures, including the limitations inherent in our determination of each of the relevant adjustments. The Non- IFRS financial measures used by E.ON may differ from, and not be comparable to, similarly-titled measures used by other companies. Certain numerical data, financial information and market data (including percentages) in this presentation have been rounded according to established commercial standards. As a result, the aggregate amounts (sum totals or interim totals or differences or if numbers are put in relation) in this presentation may not correspond in all cases to the amounts contained in the underlying (unrounded) figures appearing in the consolidated financial statements. Furthermore, in tables and charts, these rounded figures may not add up exactly to the totals contained in the respective tables and charts. Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts New segment reporting starting Q2

Reporting structure until Q1 2016 Reporting structure as of Q2 2016 Germany Generation Energy Sweden Networks Renewables CEE & Turkey Germany Global Commodities Customer Solutions UK Exploration & Production Other

Renewables Germany

Corp. Functions/ Other EU Countries Other Preussen  Discontinued operations Non-EU Countries as of AGM approval Elektra  At equity post registration of spin-off & execution of GM / Consolidation Uniper deconsolidation agreement

5 Agenda

1. Group overview 50% 50% Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts Enerjisa – Market environment Favorable growth environment

Strong macro-economic indicators

2006-2014 2015-2035

Annual Real GDP Growth 3,4% 3,5% 1,7% 0,5%

CAGR CAGR

Population 17,0% growth 10,5% 2,4% 2,3%

Growth Growth

Electricity 4,7% 4,1% consumption 0,5% growth -0,6% CAGR CAGR

Turkey EU28

Source: IHS, EIA

7 Enerjisa – Market environment

Supportive regulatory environment

Energy Networks Renewables Customer Solutions Regulatory WACC (Pre-tax, local Feed-in-tariffs 2015 Evolution of market liberalization currency)1 USD denominated (USD/ MWh) Eligibility threshold (MWh p.a.)

11,9% 73 73 25,0 6.1-8.0% 5,9% 4,5%

Turkey CEE Germany 2 Sweden 3 5,0 4,5 4,0 3,6

Wind Hydro 4 2012 2013 2014 2015 2016

Country risk premia vs. Germany Eligible Non-eligible • Stable cash flows from Regulatory incentive framework USD-denominated feed-in-tariffs • Eligibility limit for regulated tariff • Return on RAB:  (10years) consistently reduced, but, ~90% of • Opex outperformance:  residential customer accounts still • Theft & loss allowance • Yearly flexibility to opt for either within threshold outperformance:  feed-in-tariffs or market tariffs • Financing outperformance:  • Full liberalization expected, • Higher feed-in-tariff if power plant opening up new market and profit Improvement through recent parts were manufactured in Turkey pools regulatory review • WACC: 9.97% to 11.91%  • Increased allowed Capex and T&L performance 

Source : Euromonitor, EMRA, E&Y, IHS Source: EMRA Source: EMRA

1. Turkey and Sweden: Real return; CEE, Germany: Nominal return 2. Pro-forma calculated. Instead of using a WACC-approach the German regulator publishes allowed equity returns. WACC figures for existing (Return on equity: 7.14% pre corporate tax and after commercial tax) and new investments (Return on equity: 9.05% pre corporate tax and after commercial tax) are assuming c. 4% cost of debt and a 60/40 debt/equity capital structure. 8 The pro-forma WACC figure of 5.9% is then derived by weighting the share of existing assets (WACC: 5.7%) and new assets (WACC: 6.5%) 3. Pre-tax real WACC for Sweden of 4.5%; Current WACC of 4.5% challenged in court by network operators; Average inflation expectation for Sweden amount to 1.6% 4. Applicable to ~95% of the hydro installed capacity Enerjisa Recognized market leader with diversified portfolio Energy Customer Generation/ Networks Solutions Renewables4

Assets and Operating 207,000 km 9 m customer accounts, activities grid within three core mainly in Istanbul, Ankara regions of Turkey: and Adana regions Under construction1 • Istanbul: Urban Hydro 1.1 GW growth engine, mega 1.3 GW city, financial hub • Ankara: Capital, the Wind political heart 0.2 GW • Adana: high-growth Gas industrial center, young 1.1 GW and booming population

Distribution Energy Supplier Market Generator #1 Network Operator #1 by supplied energy #1 position by installed capacity2 by grid length (TWh)

EBITDA 0.9 TL bn (47% of total) 0.2 TL bn (13% of total) 0.8 TL bn (40% of total)4 5 20153

1. Capacity under construction includes CCGT, lignite and hydro plants 2. Excluding state-owned EUAS 3. Unadjusted as per Enerjisa financial statements 4. Including trading result 9 5. Including optimization Enerjisa Enerjisa has been developed into a state-of-the-art company Enerjisa – track record

Performance improvements of privatized EBITDA – 2011A-2015A1 distribution assets TL bn • New leadership and more efficient management structure • Streamlined organization 1.9 • Stakeholder management focus CAGR: 39% Capability transfer • Technical support for project development and execution 0.8 • Support for commercial and financial processes 0.5 0.5 0.5 Operational improvements • SAP roll-out at group and operating units • SCADA system implementation Footprint build-up 2011 2012 2013 2014 2015 • Acquisition of two distribution companies • Build-up of 2.5 GW generation capacity • Strong positioning of retail business through re- branding

10 1. Unadjusted as per Enerjisa financial statements Enerjisa Enerjisa generates sizeable EBITDA

Contribution to E.ON EBITDA/ Net Income mainly impacted by PPA

Enerjisa net income to E.ON contribution bridge – 20151, € m

622

-164

95 -314 51 -49 -31 -23 -24 -27

Enerjisa Depreciation Financial Tax, Other Enerjisa Net E.ON share Divestment- Acquisition- FX hedges Contribution EBITDA expenses Income 2015 (50%)2 related related and other to E.ON 2015 impairments depreciation EBITDA/ Net (one-offs) 3 charges (run- Income rate)

1. Unadjusted as per Enerjisa financial statements 2. Different FX translation methodology leads to €51 m > 50% of NI 11 3. Reversal of allocated step-up on acquired assets Enerjisa Overview of Networks regions

Ayedas DisCo1 (2015) Baskent DisCo1 (2015) 2.2 m subscribers 3.4 m subscribers 7.7 TWh consumption 16.3 TWh consumption Istanbul 2.3 Ankara

Toroslar DisCo1 (2015) Adana 3.2 m subscribers 15.9 TWh consumption

Ayedas at a glance Baskent at a glance Toroslar at a glance

 USP – Istanbul as megacity with  USP – Ankara as capital,  USP – High growth industrial strong growth (regional (financial) Turkey’s political “heart” center, booming and young hub) population  Population – 7.0 m  Population – 5.1 m  Population – 7.9 m  Area – 61,161 km2  Area – 1,898 km2  Area – 46,596 km2  Total line length – 106,144 km  Total line length – 21,191 km  Total line length – 79,705 km

Sizeable footprint Integration of new distribution companies well advanced

12 1. Distribution company Enerjisa Generation: Portfolio overview

Istanbul Arkun – 245 MW Cambasi – 45 MW Kentsa – 120 MW Ankara

Bandirma I – 936 MW Tufanbeyli I – 450 MW Bandirma II – 596 MW Alpaslan – 280 MW Yamanli II – 82 MW Canakkale Dagdelen – 8 MW Balikesir – 143 MW Menge – 89 MW – 30 MW (formerly Bares) Kandil – 208 MW Kusakli – 20 MW Sarigüzel – 103 MW Köprü – 156 MW Hacininoglu – 142 MW Incir – 170 MW Kavsakbendi – 191 MW Dogancay – 62 MW Pervari – 400 MW Dagpazari I – 39 MW

Capacities in MW Gas Hydro Wind Lignite In operation 1.056 1.292 212 Under construction 596 62 450 In development 850

13 Enerjisa The outlook for Enerjisa is solid, with positives and challenges in balance Enerjisa strategic focus for Key factors driving Enerjisa’s performance 2016 and beyond

Macro fundamentals and Enerjisa position Strong financial discipline  Power market growth still strong and regulatory  Further investments mainly in framework stable, i.e. future growth enablers energy networks and Positives intact renewables/ distributed generation and  Strong market position: Leader by most metrics, strengths strong brand  Selected disposals  Excellent operational performance: CCGT  Further debt financing benchmark competitive vs. E.ON fleet, optimization (FX, tenor, Interest successful in integration of 3 networks rates)

Generation market and Enerjisa capital structure Net Income and EBITDA1  Generation market to remain oversupplied in the TL bn near-term due to overbuild, affecting power Challenges prices and spreads 1.9  High Enerjisa financial debt resulting from 0.3 Ayedas/Toroslar acquisitions and generation investments 2015 2020 Net Income EBITDA

Medium-term IPO potential 14

1. Unadjusted as per Enerjisa financial statements Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts PreussenElektra

Asset overview

Geographic presence in Germany Overview of E.ON’s German nuclear plants

Start-up E.ON Net Shutdown year share Capacity year Brunsbüttel 1 Brokdorf (%) (MW) (AtG)

Stade Active Isar 2 1988 75.0 1,410 2022 Krümmel nuclear Unterweser plants Brokdorf 1986 80.0 1,410 2021 E.ON operator Hannover Grohnde 1985 83.3 1,360 2021 Emsland Active Emsland 1988 12.5 1,335 2022 Grohnde nuclear plants Gundremmingen C 1985 25.0 1,288 2021 Würgassen E.ON minority share Gundremmingen B 1984 25.0 1,284 2017

Grafenrheinfeld Grafenrheinfeld 1982 100.0 1,275 2015

Isar 1 1979 100.0 878 2011

Unterweser 1979 100.0 1,345 2011 Isar 1/2 Shutdown Stade 1972 66.7 878 2003 Gundremmingen A/B/C nuclear plants Würgassen2 1975 100.0 640 1994

Brunsbüttel 1977 33.3 771 2011

Krümmel 1984 50.0 1,364 2011

Active and operated by Active and minority share PreussenElektra Gundremmingen A 1966 25.0 250 1977 PreussenElektra Shut down Decommissioning

1. Atomgesetz 16 2. Start-up year 1971, transfer to Preußische Elektrizitäts-Aktiengesellschaft in 1975 PreussenElektra Safe and efficient operations

Three active power plants1 Excellent fleet track record

Shut-down dates • On average >90% availability over the last 5 years 2021 Grohnde (1,360 MW) • Earnings with near term visibility through forward hedging (>2 years) • Controllable operational costs development (incl. capex)2: 2021 Brokdorf (1,410 MW)

Controllable costs, indexed to 2011 = 100 3

2022 Isar II (1,410 MW) -25%

100 88 87 84 75 Financials ~€0.8 bn4 EBITDA 2015

~€0.6 bn4 EBIT 2015

~€0.1 bn5 Capex 2016-2018 2011 2012 2013 2014 2015

1. Nuclear plants which have been shut down and are in majority owned by E.ON include Grafenrheinfeld, Unterweser, Isar 1, Stade, Würgassen. Active joint nuclear plants are Gundremmingen B & C and Emsland 2. Including Brokdorf, Grohne and Isar 2. Controllable costs only include cost components that can directly be influenced and are not mainly driven by external factors (e.g. no nuclear fuel tax and nuclear fuel costs are included) 3. Average across German nuclear power plants operated by E.ON 4. Based on pro forma figures - including participation income and effects from nuclear fuel cycle 17 5. Operational capex not taking into account decommissioning PreussenElektra

Near term visibility through forward hedging

PreussenElektra forward hedging overview 2016-2018

Hedged volumes (%)

37.6 32.9 26.6

100% 100%

82%

2016 2017 2018

Forward hedged price (€/ MWh)

18 PreussenElektra

Overview nuclear provisions

€ m FY 2015

Retirement and decommissioning 7,857

Containers, transports, operational waste, other 2,902

Interim storage 2,205

Schacht Konrad final storage facility 1,363

Final storage facilities for high active waste 2,647

Total nuclear provisions in economic net debt 16,974

19 Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts A higher share of regulated / long-term contracted earnings following spin-off

Business profile post spin-off E.ON’s attractions

+ Substantially increased earnings stability High share of regulated / long- ~65% from regulated / long-term  term contracted earnings contracted businesses2

~€5.0 bn1

Diversified portfolio  EBITDA 2015 Energy Networks Renewables Customer Solutions PreussenElektra and others High cash conversion + Operations mainly under stable, well  established regulatory frameworks in low risk markets + Sharply reduced commodity & FX risk Attractive return on capital exposure  - Reduction of overall size and diversification

1. Pro-forma figures – without Uniper contribution and excluding results from divested operations 21 2. Including Energy Networks, ~40% of Heat and ~60% of Renewables Profit & Loss Statement1

€m 2015

Group EBITDA 5,844

D&A -2,281

EBIT

Energy Netw orks 1,811

Renew ables 391

Customer Solutions 806

Corporate functions/ other -403

Core EBIT 2,604

PreussenElektra 563

Divested operations 395

Group EBIT 3,563

Financial results -1,485

Income taxes -710

Non-controlling interests -270

Underlying net income 1,098

Other non-operating results -8,097

Net income/loss attributable to shareholders of E.ON SE -6,999

22 1. Pro-forma figures Cashflow Statement1

€m 2015

Cash provided by (used for) operating activities before interest and taxes

Energy Netw orks 1,637

Renew ables 563

Customer Solutions 1,581

Corporate functions/ other -265

Core cash provided by (used for) operating activities before interest and taxes 3,516

PreussenElektra 391

Divested operations 841

Group cash provided by (used for) operating activities before interest and taxes 4,749

Interest payments -619

Tax refunds (net) 61

Cash provided by (used for) operating activities 4,191

Purchase of invesments in intangibles, property, plant and equipment and equity investments -3,227

Proceeds from disposal of intangibles, property, plant and equipment and equity investments 2 4,522

Changes in restricted cash and cash equivalents 148

Cash provided by (used for) investing activities 1,442

1. Pro-forma figures 23 2. Including proceeds from disposal/purchase of securities, financial receivables and fixed-term deposits as well as contributions to pensions Economic Net Debt

€m 31 Dec 20151

Liquid funds 7,829

Non-current securities 4,536

Uniper receivable (financial receivables) 11,626

Financial liabilities -15,791

Uniper payable (financial liabilities) 2 -8,547

Adjustment FX hedging3 218

Net financial position -129

Provisions for pensions -3,281

Asset retirement obligations4 -17,930

Economic net debt5 -21,340

Source: Spin-off Report, E.ON

1. Differences might occur due to rounding 2. Net figure; does not include transactions relating to our operating business 3. Net of profit and loss sharing agreements with Uniper 4. Thereof 16,974m related to nuclear AROs 24 5. Not including Nordstream transfer, capital measures and repayment of E.ON loan Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts Energy Networks

Overview

E.ON’s network presence Overview Network Market length share  Leading European operator of electricity (tkm) (%) and gas networks supplying several million customers P G P G  Strong positioning based on €18 bn Germany 351 59 19 11 RAB1 and geographically diversified Sweden 137 2 24 60 asset base in six countries2 Hungary 84 18 52 21  E.ON ensuring efficient grid expansion Romania 55 21 17 49 using ultra-modern technologies Czech R. 66 5 28 6 Slovakia 38 - 43 -

EBIT breakdown 20153

CEE & Gas Turkey 4 5 20% 18% 62% ~70% GER SWE Power

1. Current total RAB of country/region, relevant for 2016 - In general, RABs from different regulatory regimes are not directly comparable due to significant methodical differences. These include for example different regulatory asset lifetimes, asset valuation methods, or treatment of customer contributions for network connections. For example in Sweden, the calculation of the asset base takes into account standard costs instead of actual costs. 2. Excluding Turkey 3. Pro-forma figures 4. Including at-equity result from Slovakia and Turkey 26 5. Differences might occur due to rounding Energy Networks

Financials 1

EBITDA 2 3 EBIT 2 3 OCFbIT 2 3

€ m € m € m 47% 51% 34%

2.733

558 1.811 489 1.637 354

530 329

543 1.686 1.129

564 4

2015 2015 2015

Germany Sweden CEE & Turkey Contribution to E.ON Group (Group result)

1. Pro-forma figures 2. Including Slovakia and Turkey at equity 3. Differences might occur due to rounding 27 4. 2015 impacted by negative one-off working capital effects Energy Networks Additional earnings from efficiency, investments and non-regulated activities

Indicative EBITDA pro-forma Germany Sweden CEE7 components

Return on RAB + Regulatory D&A1 ~€1.05 bn ~€470 m ~€454 m8 (2015) (~63% in 2015) (~96% in 2015) (~84% in 2015)

Normalized additional components (% of total EBITDA on a normalized level)2

Additional Based on grid 3 7%-9% N/A5 N/A5 remuneration expansion

Operational Performance- 5%-7% 5%-7% 7%-9% efficiency specific

Non-regulated Slowly 6%-8% 1%-3% 2%-4% earnings growing

Other 15%-17%4 4%-6%6 1%-2% earnings Varying

1. RAB multiplied with pro-forma WACC plus regulatory D&A 7. Includes the Czech Republic, Hungary, and Romania (Slovakia and Turkey are not included) 2. For years 2016-2018 8. In Hungary E.ON has to pay the so-called “utility tax” in an annual amount of 3. Grid expansion for Germany HUF12.5 bn (~€39 m). This tax is not recognized (as OPEX) by the Hungarian 4. Including income from minority participations in other regional utilities (~ €140 m) Regulator. For the purpose of this analysis we reduce the “Return on RAB” by HUF12.5 bn to 5. RAB adjusted for investments during regulatory period show the effective regulatory performance 28 6. Difference between regulatory and IFRS accounting Energy Networks

Regulatory D&A

Average D&A p.a. by geography (2016-2018)1 2016-2018 Capex / Regulatory D&A

155%

€0.47 bn, 45% 127% €0.28 bn3, 27% 116%

€1.04 bn

2 €0.28 bn, 27% Germany Sweden CEE

Germany Sweden CEE2

1. Differences might occur due to rounding 2. Excluding Slovakia and Turkey 29 3. Due to start of new regulatory period in Hungary, assuming 2017 and 2018 regulatory D&A equal to 2016 Energy Networks

GER Introduction to German operations

E.ON’s networks presence1 Capex split 2016-2018

€1.3 bn, 59%

(66.5%) €0.9 bn, 41% (67%) €2.2 bn

(61.5%)

Growth Replacement & other

Sector & business specifics  Highly fragmented, more than 800 network operators in Germany  5,400 concessions granted by municipalities are the basis of our business, which is the largest among network operators in Germany  Our networks are concentrated in rural areas (100%)  Therefore we are positively affected by the “Energiewende” and the installation of renewables capacity

30 1. Including network presence of E.ON‘s 110kV grid, excluding lost concession areas Energy Networks

GER Regulation – General overview

Process steps of regulatory system

 Revenue cap incentive regulation Cost Audit  Cost audit and benchmarking once per + every 5 years regulatory period (5 years) Benchmarking  Total costs of historic base year basis for benchmarking & revenue cap  Efficiency level determines revenue path of regulatory period

 Yearly adjustment of revenue cap by Yearly yearly adjustment  Consumer Price Index (CPI) revenue cap  General efficiency factor of currently 1.5%  Individual efficiency factor from benchmarking

Grid yearly application  DSO applies yearly for grid expansion expansion & adjustment  Increases revenue cap within a regulatory period

 Based on revenue cap, estimated energy consumption and Network tariff yearly adjustment income differences (too high/ low) from prior years  Differs for different network areas within Germany

31 Energy Networks

GER Regulation – Regulatory schedule

Power distribution1 Commentary 1st regulatory period 2nd regulatory period 3rd  Cost of base year 2011 are basis for allowed revenues from 2014 onwards

 Regulatory cost audit and benchmarking took place from mid 2012 to end 2013

 Replacement investments in the years 2012 to 2016 are reflected in allowed revenues from 2019

onwards Base year Base

Base year Base Cost Audit Cost Audit + +  Benefits from performance measures effective in Benchmark Benchmark the years 2012 to 2016 can be kept until 2019

 3rd regulatory period for gas beginning already in 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2018

 Regulatory cost audit gas will start in 2016

Revenue cap (individual efficiency = 100%)  Final decision by the regulator on the allowed Cost base for revenue cap (illustrative) revenues gas expected in the second half of 2017

32 1. For gas distribution: first regulatory period ended 2012. Therefore the base year for the second period was 2010. The second period for gas lasts from beginning of 2013 to the end of 2017 Energy Networks

GER Building blocks of allowed revenues

Schematic illustration for 2015 (power & gas)

€10.0 bn

€0.3 bn

Gas Gas

(New)

€2.3 bn

Gas (Old)

Totex indexed to

CPI and subject to general and individual

€2.2 bn efficieny targets

(New)

Power Power

~

Power

3.3

bn

€5.1 bn

Opex

(Old)

Power Power

~ €

Capital Gas

0.7 bn 0.7 40% 40% Cap

Costs

1

2

through items through

-

Regulated asset base asset Regulated costs Current Old assets: costs Historicassets: New base Debt (related to actual capital 60%) minimumstructure, base Equity Regulated (related to regulatory maximumstructure, capital 40%) Equity on Return 7.14% Old assets: 9.05% assets:New exc. on Equity Return for equity of in ~4% excess 40% tax Trade allowance allowanceDepreciation (based on 40 usually years regulatory lives) asset costs Operating allowance (based on ofactual costs base year) historic allowedbase cost Total (Totex) revenues Additional expansion, (network bonus/ quality penalty…) recoveries Lagged (netting of actual vs. revenues) allowed Pass of higher grid (charges pensions, levels, etc…) revenues Allowed

1. Old assets are those capitalized before 01/ 01/ 2006. New assets are those capitalized after 01/ 01/ 2006. Old assets are indexed up to 40% with asset-specific indices to determine the current costs. Relevant asset base for power 2011, for gas 2010. 33 2. Return on Equity rate is post trade tax and pre corporation tax Energy Networks

GER Business with 5,400 concessions

Good track record in the past Confident for future competition

• The German Networks business is based on • Future renewals predictable and no real peaks long-term concessions granted by municipalities for the next round of concession renewals in the network area • Positioning ourselves as preferred regional • Renewal of concessions every 20 years partner via superior customer service and • Of all expiring concessions since 2007, more operational excellence than 90% renewed1, which means losses are less than 1% per year • Loosing an expiring concession triggers a mandatory disposal of assets to concession holder which means cash-in for E.ON

8% Track record Renewal rate in % of in % of revenue cap revenue cap2 30% 30% 20% 15% 5%

92% currently >5 years 5 - 10 10 - 15 >15 years lost renewed open years years 2007 TODAY 2036

1. In % of revenue cap; loss of Gas concession of City of Hamburg in 2017 not included (Otherwise 88% renewed) 34 2. Only concession based business, which means high voltage business (110kV) excluded Energy Networks

SWE Introduction to Sweden operations

E.ON’s networks presence Capex split 2016-2018

Power €0.5 bn, 52%

€0.5 bn, 48% €1.0 bn

Growth Replacement & other

Sector & business specifics

 Highly fragmented distribution market with ~165 distribution companies with strongly differing Gas potential to handle current and future challenges  E.ON is the largest local network operator in the market  E.ON has mainly grids in the country side  E.ON has a good reputation among stakeholders  Great focus on connection of large wind farms in recent years, offering attractive future business areas

35 Energy Networks

SWE Regulation building blocks of the allowed revenue

Principles of regulation model Regulatory model 2016-2019

OPEX 4 CAPEX Non-influenceable Influenceable costs Asset base including investments costs 2 Efficiency Depreciation Return Demands

Operational Costs Cost of Capital 1

Quality Adjustment 3

Revenue Cap (~€4.0 bn)1

1 CAPEX: Real linear calculation of capital cost. No asset considered older than 38 years when the period starts (2016). Limited contribution to revenue cap between 40-50 years 2 OPEX: Historic costs 2010-2013 used as base. DEA2 method used for efficiency requirements • Revenue regulation is an important part in the pull set-up of regulations 3 Quality: Differentiated quality cost for different customer categories, expected security of supply • 1st period revenue regulation period 2012-2015 based on the whole industry’s performance • 2nd period revenue regulation period 2016-2019 4 SMART transformation: Incentives given for efficient grid operation (grid losses and load factor)

1. Gross revenue cap for 2016-2019 , excl. intercompany eliminations of ~€540 m 36 2. Data envelopment analysis Energy Networks

SWE Build-up of regulatory asset base

Company’s real assets Regulators standard price list  Lines  Meters  Lines  Meters  Cables  Others  Cables  Others  Transformers  Transformers

Standard price by component (~800 standard components)

Component x Price = • Replacement value

Replacement value by Age profile year

• Regulatory Asset = Base (RAB)

Linear depreciation

37 Energy Networks

SWE Deep dive – improved performance and stable business

Intra-market benchmark base for development Improved performance by outsourced business

EBIT / CSV  Since 2014, business model based on competitive contractor management Controllable Opex  New period of contracts from 2016 (4 year period) Grid losses / CSV  Very competitive contractor markets in all geographical areas  Foresee a better cost and performance situation in contractor management for 2016-2019 SAIDI unplanned Capex / CSV  Evaluated and applied experiences from earlier periods to optimize commercial conditions in new contract period E.ON Ellevio Vattenfall Industry

Connection of wind power parks

MW/ year MW/ Acc  Connection of wind power parks has increased last 8-9 400 3.000 years  Currently, weak business cases for wind power companies 300 2.250 due to low market prices on energy and green certificates  Still high request from developers for pre calculation and 200 1.500 preparatory work  E.ON involved in pre calculation of projects with approx. 100 750 2,000 MW  Connections are mandatory as long as sufficient capacity in 0 0 the network exists – investments are reflected in RAB  In case sufficient network capacity is not available, park Installed Renewable Forecast/ Year owners are required to fund the connection

Acc Acc Forecast

38 Energy Networks

CEE – Overview

E.ON’s network presence Capex split 2016-20182

€0.6 bn, 60% €1.1 bn

€0.4 bn, 40% Growth Replacement & other Power Gas Power & Gas Region specifics Power & Gas Power Gas  Strong investment incentive, high WACC and need of high investment volumes due to increased grid replacement E.ON grids2  Gradual deployment of smart metering and other P: 6,700 intelligent grid components Grid customers (k) G: 2,400  Government support of “clean mobility” – electro mobility and CNG1 P: 243 Grid length (tkm)  Currently stable energy consumption with expected G: 44 modest growth

1. Compressed natural gas 39 2. Excluding Slovakia and Turkey; Differences might occur due to rounding Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts Customer Solutions

Overview

E.ON’s Customer Solutions presence Overview

 Covers energy sales (power & gas), heat as well as new solutions  Serving B2C/ B2B SME customers with “asset-light” and mass market solutions  Serving B2B large/ B2M customers with “asset-intensive”/ tailored solutions

EBIT breakdown 20153 Energy sales Heat & new District heating solutions New solutions 2015 Other (B2B Large/ B2M) 1 Germany Customer accounts 23 m 16% ~15%

3 49% EBIT ~€0.8 bn 35% ~85% 150 / 167 Power/ gas volume sold UK TWh2 Energy sales and new solutions (B2C/ B2B SME) Average EBIT margin ~3%3

1. Excluding Turkey, including 49% stake in ZSE (Slovakia) 2. Excluding power/ gas volumes for heating 41 3. Pro-forma figures Customer Solutions

Financials1

EBITDA2 EBIT2 OCFbIT2

€ m € m € m 19% 23% 33%

1.581

365 1.112

258 806 487 130 452 397 729 402 278

2015 2015 2015

UK Germany Other Contribution to E.ON Group (Group result)

1. Pro-forma figures 42 2. Differences might occur due to rounding Customer Solutions

Overview customer segmentation Energy sales and new Heat & new solutions solutions (B2C/ B2B) (B2B/ B2M)

Customer B2B SME2 groups B2C1 B2B large3

B2B large3 B2M4 Commodity only

Customer • Simplicity & affordability (“How can I • Reduce energy costs or achieve needs save costs with low effort?”) compliance • Convenience & comfort • Become sustainable for own customers/ • Specific to sub-segments: How to citizens become more sustainable, compliant • All-round carefree energy-related and self-sufficient? optimization • Financing solutions

Key E.ON • Superior scale of customer base and • Strong track record in heat and onsite advantages operations generation • Existing customer relations as • Vendor & technology neutral: best foundation for up- and cross selling of customer solution new services • Integrated offerings and end-to-end • Customer insights and understanding solution delivery • Trustful and strong partnerships with municipalities

1. Domestic customers, e.g. families, single-households (B2C = Business to consumer) 2. E.g. developers and landlords, hotels, farmers, small and home-offices (B2B = Business to business) 3. E.g. commercial chains, large manufacturers, large hotel chains (B2B = Business to business) 43 4. Municipalities Customer Solutions – Energy sales

Country profile - UK

Operations overview – 2015

Power: Gas: 41 TWh 7,6 51 TWh

TWh Sold Number of customer accounts (m) Key competitors and market shares Country trends

Power1 Gas2  Competitive market with comparatively high 34% Centrica Centrica churn rates 24% 37%  Extensive regulatory agenda through Ofgem E.ON E.ON 25% 16% 12% and Competition and Markets Authority review

SSE 16% SSE 6%  New entering smaller suppliers with growing 13% market share EDF RWE 5% 12% 9%  Digital solutions as key development trigger for Scottish future solutions business RWE 11% 1% Power 9% Source: Ofgem Non-household Household

1. Q3 2015 domestic market share 44 2. Non-household: End of 2013 market share; Household: Q3 2015 market share Customer Solutions – Energy sales

Country profile – Continental Europe1

Operations overview – 2015

Power: 15,4 110 TWh

Gas: 116 TWh

TWh Sold Number of customer accounts (m) Market shares2 Country trends

Power Gas3  Retail market situation strongly differs: ranging Hungary 34% 11% from fully competitive markets (e.g. Sweden, Slovakia 21% 2% Germany) to partly competitive (e.g. Romania) Czech Republic 20% 8%  Trend towards customer demands for new solutions and expanded service offerings Germany 20% 10%  Increasing number of customers demand Sweden 11% 19% digital services and solutions Italy 3% 4% Romania n.a. 23%

Source: E.ON, BDEW

1. Including Germany, Romania, Hungary, Czech Republic, France, Slovakia, Sweden, Italy 2. 2014 market shares, Germany gas share based on E.ON sales volume in 2015 and market size of 2014 45 3. From 2016 customer based reduced by 600 k USP gas customers in Hungary Customer Solutions – Energy sales

Country profile – Continental Europe (cont’d)1

Customer Power sales Gas sales accounts (m) (TWh) (TWh) 2015 Germany 6.2 46 52

Romania 3.1 5 25

Hungary 2.4 14 10

Czech Republic 1.3 16 15

Slovakia 0.9 6 2

Sweden 0.7 15 2

Italy 0.7 8 11

Total 15.4 110 116

46 1. Including Germany, Romania, Hungary, Czech Republic, France, Slovakia, Sweden, Italy; differences might occur due to rounding Customer Solutions – New Solutions (B2C/ B2B SME)

B2C Solutions overview – selected examples

PV/ battery Customer engagement

Smart check Saving energy toolkit (SET)  PV B2C ~3,500 PV contracts signed  Smart Check with ~35,000 customers in Germany,  PV & battery launched in April 2016 for B2C customers growing by ~10.000 registered users a month  „Solarprofis“: 170 O&M contracts signed in first 7 weeks  SET in the UK (~1 m SaaS1, 0.8 m active)

Connected home Value added services

 Over 65,000 connected home devices deployed in large  C. 400,000 customers make use of value added services, scale pilot projects such as energy-related insurance services

47 1. Software as a Service provider: Opower Customer Solutions – New Solutions (B2C/ B2B SME)

B2B SME solutions case studies

Lighting PV Digital audits

Customer Customer Energy Toolkit Tylex Letovice is a Czech textile Microart e. K. based in Roding (Bavaria) • Web-based advice on energy manufacturer (home and technical is a specialist in producing precision efficiency measures, personalized by textiles) with more than 180 years components and systems each customer`s business and meter tradition data Solution • Energy saving advice hotline staffed Solution • Realized in less than 3 weeks time with engineers • Project on lighting upgrade at • Optimized for customer’s own • Over 40% of users have visited the customer site and a financing solution consumption, with produced power dashboard more than once • E.ON decreased the lighting energy nearly 100% self-consumed • More than 10% indicating interest in consumption by 80% and increased • Reduces energy costs and CO2 their recommended energy savings brightness level with payback period emissions at the same time measures up to 1.5 years

Prior Now

80% 1.5 years 150 MWh 84 tons 400,000 15% Reduction of lighting Power production CO emission Eligible SME Average savings Payback period 2 energy consumption annually reduction annually customers opportunities

48 Customer Solutions – Heat

Country profile - Germany

Operations overview – 2015 Attractive locations

District and local area heating  District heating concentrated in the urban regions of Hamburg and Saxony-Anhalt  Local area heating especially concentrated around Munich and Bavaria in general as well as Northern Germany Strong stakeholder relationships  Regional presence and valued competence as heat supplier and DSO2 enables the implementation of Customer Solutions and long-term relationships Country trends

Local area heating  Growth with local area heating concepts, especially in urban areas Sustainable cities  Brownfield approaches to develop new or to transform existing city areas following a sustainability approach Key competitors and market shares

Gas-based heat and CHP Heat grid District heating3 Distributed solution renewable Other „Energiewende“ projects Vattenfall 16% ~2.7 TWh heat and ~0.5 E.ON 6% ~140,000 customers1 TWh power sold RWE 5%

1. Incl. households contracted via business customers 2. Distribution system operator 49 3. Source: Monopoly Commission – Sector Assessment District Heating 2012 Customer Solutions – Heat

Country profile - Sweden

Operations overview – 2015 Attractive locations and growth opportunities

District heating  Large scale, profitable heat systems in three main metropolitan areas of Sweden (Malmö, Norrköping, and Örebro)  Growth opportunity in Stockholm being developed  Further heat systems in urban areas across Sweden  Competition mainly from alternative heating solutions (i.e. heat pumps) Strong stakeholder relationships and acceptance  High penetration and strong customer acceptance of heat as renewable and sustainable energy source Stockholm area  Recognition as long-term reliable partner opens opportunities with Örebro municipalities and businesses for growing existing heat footprint  Climate friendly production due to more than 80% of heat supplied coming from renewables or recycled energy Country trends

Norrköping District heating transformation Malmö  Further integration of renewable heat sources  Extension of district heating and power distribution to sustainable city concepts, e.g. already proven in Malmö  Flexible customer solutions with increased product offerings including financial solutions will serve increasingly as competitive advantage

~220,000 households ~5.7 TWh heat sold Key competitors and market shares supplied1 District heating

Fortum 14% E.ON 11% Göteborg Energi 7% Vattenfall 6% 50 1. Incl. households contracted via business customers Customer Solutions – Heat

Country profile - UK

Operations overview – 2015 Attractive locations

Local area heating  Extensive footprint of local area networks across UK urban and metropolitan centres. Current focus on London, but opportunities Scotswood, present at a national level Newcastle  Established capabilities in sustainable and profitable heat and power production and project delivery for biomass plants Strong stakeholder relationships  Delivery track record and very good capability set makes us Stevens Croft recognized as attractive partner for heat networks Blackburn Meadows, and Bradford Country trends Port of Policy driven growth  Distributed heat market expected to grow 30% annually until 2020 Stoke driven by carbon and building policies Bath  Significant government commitment to the development of district Cranbrook & heating networks Monkerton, Introduction of regulation Exeter London  Introduction of the heat metering & billing regulations and the 31 schemes establishment of the heat trust, a voluntary code of conduct Devolved responsibility  Local authorities passing the burden of low carbon targets to Southampton Newbury developers via planning permission process, creating B2B relationships Local area heating systems CHP and biomass sites Key competitors and market shares

~15,000 customer 2 1.1 TWh heat sold1 District heating contracts E.ON 12%

Cofely 11%

1. Sold to customer accounts and via business heat power solutions including O&M contracts. Excluding sites E.ON only operates but does not own 51 2. For new builds Customer Solutions – New solutions (B2B Large / B2M)

Onsite generation UK

Leeds Stevens Croft: Biomass Power: 4.5 MW Power: 43 MW Steam: 22 MWth Heat: 6 MWth Client: St James University Was named Scotland’s best Hospital renewable energy project

Bradford Stoke Power: 4.5 MW Power: 0 MW Heat: 19 MWth Heat: 64 MWth Client: Nufarm Client: Michelin Tyres

Blackburn Meadows: Biomass Power: 28 MW Power: 4.9 MW Heat: 25 MWth Provides power for 40,000 homes Heat: 52 MWth by converting recycled waste wood Client: Queens medical center

Port of Liverpool Kemsley 2 Power: 30 MW Power: 0 MW Heat: 70 MWth Heat: 24 MWth Clients: Cargill, Peel Ports Client: DS Smith Paper

Overall characteristics UK: 1  Overall capacity operated : >800 MWth  Lead times up to 6 years  Mainly CHPs with capacity of 5-50 MW  Contract durations of up to 15 years

52 1. Capacity related to regional unit UK owned and managed assets as well as assets only managed by regional unit UK Customer Solutions – New solutions (B2B Large / B2M)

Onsite generation - Continental Europe above 10 MW

Kraftwerk Marl Industrial plant Greifswald Power: 60 MW Power: 37 MW Steam:100 MWth Steam: 47 MWth Client: Evonik Client: OPAL Gastransport

CHP-Plant Antwerpen CHP-Plant Hattorf Power: 80 MW Power: 30 MW Steam: 120 MWth Steam: 60 MWth Client: Evonik Degussa Client: K+S

CHP-Plant Grenzach-Wyhlen CHP-Plant Gendorf Power: 40 MW Power: 41 MW Steam: 75 MWth Clients: DSM, BASF Steam: 90 MWth Client: Chemiepark Gendorf

CHP-Plant Plattling CHP-Plant Burghausen Power: 125 MW Power: 120 MW Steam: 150 MWth Steam: 350 MWth Client: UPM Client: Wacker Chemie

Overall characteristics 1  Overall capacity operated : ~600 MWel  Lead times up to 6 years  Mainly gas-turbines of 5-200 MW  Contract durations of 13 – 15 years

53 1. Owned and managed by E.ON as well as only managed by E.ON Customer Solutions – New solutions (B2B Large / B2M)

Onsite generation - Continental Europe below 10 MW

Reha clinic, Buckow Power: 45 kW Otto E-Commerce, Hamburg Heat: 90 kWth Power: 2 MW Oil-fired heating system replaced, 205 t CO2 savings per year Heat: 14.6 MWth Extended heat capacity via CHP integration into heat grid

Airport Berlin Brandenburg Power: 8 MW Heat: 10 MWth Third largest cold storage in Germany City of Oldenburg: Heat Power: 1.7 MW Heat: 2.1 MWth Supplies ca. 300 housing units via heat grid Hospital Bayreuth Power: 711 kW Heat: 1.1 MWth 25% energy-cost savings Redwitz municipal (Bavaria) Power: 15 kW International packaging Heat: 30 kWth Supplies heat for a school and open company air swimming pool Power: 4.4 MW Heat: 1.6 MWth 20% reduction of energy cost, 6,300 tons of CO2 saved annually

Overall characteristics  Tailored solutions according to customer needs 1 2  Overall capacity operated : ~1,100 MWth  Contract durations of 10 – 15 years  Mainly CHPs/CHCPs up to 10 MW, heat  Close collaboration with local partners necessary pumps and boilers

1. Owned and managed by E.ON as well as only managed by E.ON 54 2. Including Sweden Customer Solutions – New solutions (B2B Large / B2M)

Onsite generation case studies: Queens Medical Center and Friatec

Customer Queen's Medical Centre in Nottingham is the largest hospital in the UK and a center of excellence in patient care, teaching and research

E.ON solution  Gas turbine installation generates electricity & steam used for heating, cooling (absorption chillers) and equipment sterilization  CHP plant was installed to supply the hospital's energy needs over 15 years  Maintenance done by E.ON UK Reduction in carbon emissions of 16,000 t Save 42% of the annual energy consumption a year or 38%

 E.ON to build, own and operate Europe’s first fuel cell power plant of MW size Friatec  1.4 MW fuel cell with an electrical efficiency of 47% planned to go into operation in June 2016

55 Customer Solutions – New solutions (B2B Large / B2M)

Energy efficiency concept

Energy performance contract concept

Customer’s future energy cost without E.ON involvement Start of E.ON involvement

Customer share of savings

E.ON share of savings Historical customer energy cost Customer’s future energy cost after E.ON involvement

Time Operation, maintenance & continuous optimization

 Delivering life-time energy and operating cost savings to our customers  Savings guarantee for customers

56 Customer Solutions – New solutions (B2B Large / B2M)

Energy efficiency case studies

Energy efficiency examples

Large tire manufacturer  Energy performance contract across 6 plants in Europe  Design, installation & operation of highly efficient heating, ventilation, compressed air & lighting systems

30-89% reduction of energy costs1

Large pharmacy chain  Energy data management and in-store energy dashboard across 1,300 stores  Building energy management system for HVAC2 and intelligent lighting control across 100 UK stores

20% reduction of energy costs3

 Energy efficiency – helping customers to reduce energy consumption  E.g. through remote control and optimization of assets at customer facilities, >32,000 sites under management  E.g. efficient lighting solutions – 20 large scale and >50 mid-sized projects delivered

1. Range across all sites; savings refer only to components optimized by E.ON 2. Heating, ventilation and air conditioning 57 3. Average across all 100 stores, with individual site savings ranging from 5-44%; savings refer to total annual energy costs Customer Solutions – New solutions (B2B Large / B2M)

Flexibility case studies

Customer Customer German producer of A group of 11 entrepreneurial metallurgical silicon operating agriculturalists have joined four electric arc furnaces with a forces to own and operate a nominal capacity of 54 MW in biogas CHP plant the TenneT balancing zone

E.ON solution E.ON solution  Identify demand response  E.ON markets the generation capacity of the furnaces, and flexibility of the biogas plant to connect them to E.ON’s virtual the grid, allowing the customer power plant engine to generate revenue from  Pre-qualify capacity with spare capacity TenneT  Innovative project delivered a  Market demand response complete in-house Virtual capacity“Demand to TenneT Response” and Power“Demand Plant (VPP) Response” platform dispatchup toloads whenever  Reducedup to equipment and requested maintenance costs Benefits E.ON achievements 15 MW • Revenue from spare heat and power capacity Monetize customer’s secondary balancing • Subsidy for renewable energy and flexibility power controllable loads • Innovative VPP solution for small onsite generators

58 Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts Renewables 1 Portfolio overview

E.ON Renewables Footprint (2015) Owned Onshore Production Average installed Wind + PV volumes2 revenue3 capacity1 2,310 MW5 ~5.3 TWh ~45 €/ MWh

328 MW ~0.6 TWh ~150 €/ MWh

257 MW ~0.7 TWh ~126 €/ MWh

159 MW ~0.4 TWh ~102 €/ MWh

155 MW ~0.4 TWh ~64 €/ MWh

117 MW ~0.4 TWh ~48 €/ MWh

Owned Offshore installed Production Average 2 3 wind capacity1 volumes revenue 646 MW ~2.0 TWh ~177 €/ MWh

317 MW ~0.5 TWh ~179 €/ MWh

Operated capacity countries 48 MW ~0.2 TWh ~51 €/ MWh Project pipeline only 41 MW NA4 NA4

1. Owned installed capacity as of 31 December 2015 including Amrumbank at 100%. Additionally, offshore wind adjusted for upgrade of Amrumbank to 301 MW in February 2016 2. Pro rata net production volumes for owned capacities in full year 2015. Net generation volumes defined as gross generation volume minus own consumption and line losses 3. Average revenue includes subsidies/ incentives (e.g. Production Tax Credit (PTC), Renewable Obligation Certificates (ROCs) etc.). E.ON reported financials classifies some of these components as other income 4. For Rodsand, production volume is not consolidated, however for the attributable capacity, 20% of Rodsand are considered

60 5. Thereof 19 MWDC PV Renewables

Financials1

EBITDA EBIT OCFbIT 2

€ m € m € m 13% 11% 12%

750

563

391

2015 2015 2015

Contribution to E.ON Group (Group result)

1. Pro-forma figures 61 2. Cash generated from PTC scheme is not visible in the OCF bIT Renewables

1Current regulatory regimes and frameworks

Remuneration scheme by geography Market Highlights Summary US:  Tax Credits (PTC and ITC)  Accelerated Depreciation (MACRS)  Renewable Portfolio Standards (RPS) UK:  Renewable Obligation Certificates (ROC)  Contracts for difference 913 (CfD)  Levy Exemption PAYMENT MECHANISM Feed-in tariff Certificates (LEC) have Premium been withdrawn (Aug Quota obligation & tradable certificates 2015) Others Germany:  Feed-In Tariff (FIT) with ALLOCATION direct marketing obligation Competitive auctions for German offshore Auctions legislated but yet to be held or pilot auctions only  For upcoming new projects SUBSIDY BUDGET remuneration will be Capped determined through tender processes Source: Bloomberg New Energy Finance

62 Renewables

Current regulatory regimes and frameworks (cont’d)

US UK GER

Onshore Offshore Offshore  Remuneration based on wholesale  ROC per MWh  FIT with direct marketing obligation market or PPA, plus certain incentive  Term: 20 years  Remuneration (EEG 14): features  Remuneration: Wholesale price plus - Initial tariff: €154/ MWh for 12 years  Production Tax Credit ($23/ MWh)1 1.8-2.0 ROC/ MWh based on COD (standard) or €194/ MWh for 8 years  Renewable Energy Certificate (driven  Applicable for all E.ON offshore parks (“Stauchungsmodell”) by state-level Renewable Portfolio in UK - Base tariff: €39/ MWh Standards (RPS)  Move to CfD system from 2014 - Initial tariff extended for deep waters/  Accelerated Depreciation for tax equity (strike price in first auction distance to shore investors and developers (MACRS) £114.39-119.89/ MWh)  Applicable for all E.ON offshore parks in Germany Solar Onshore  Projects commissioning in 2021 or  Remuneration based PPA plus certain  Wholesale price plus ROC (new later subject to auction system incentive features projects eligible for COD April 2016)  Investment Tax Credit  Term: 20 years Onshore (30% of investment)2  Remuneration: 0.9 ROC/ MWh  FIT with direct marketing obligation  Renewable Energy Certificate (driven  Applicable for all E.ON onshore  Term: 20 years plus the year of start of by state-level Renewables Portfolio  Ongoing transition period between operation (initial tariff for min 5 years Standards (RPS) ROC and a CfD auction system followed by base tariff)  Accelerated Depreciation for tax equity  First CfD auction was held in February  Remuneration (EEG 14): investors and developers (MACRS) 2015 (strike price £79.23-82.50/ MWh) - Initial tariff: €89/ MWh - Base tariff: €49.5/ MWh  From 2016: ~0.4% quarterly digression  Applicable for all E.ON onshore parks in Germany  Auctions to be introduced in ‘16

1. Production Tax Credit (PTC) annually inflation-adjusted, paying out over 10 years. Full value for projects that have begun construction before 2017, then gradually decreasing until no PTC for projects beginning construction after 2019. Investment Tax Credit (ITC) also applies to wind: 30% for projects that have begun construction before 2017, and then gradually decreasing until expiring in 2020 63 2. Investment Tax Credit (ITC) for Solar amount to 30% for projects that have begun construction before 2020, then gradually decreasing until 10% level for projects starting construction after 2021 Renewables We serve customers & partners with attractive propositions

Our offering Our customers (examples)

Green energy Providing long-term Power Purchasing Agreements (PPA) to Utilities and B2B customers1

Green assets Monetizing parts of our development pipeline and operating asset portfolio through establishing long-term partnerships

Services Offering full scale operations, maintenance, asset & energy management services to Example third party asset owners

1. Including selling renewable energy to customers across Europe via our local retail organizations Renewables

Portfolio wind yield overview Our portfolio captures most attractive wind locations Site selection approach

Site characteristics significantly influence returns through load factor, costs and risks:  Continuous market scouting, as new sites become accessible  World class skills in wind and solar yield analysis and site assessment  Careful consideration of distance to shore and water depth for offshore projects Example Offshore: Rampion  The closest to shore with lowest water depth at each tender round in the UK1 Example Onshore: Grandview  Potential 1 GW site in Texas  Load factor can reach >50%

Wind Onshore Wind Offshore  Secured by early analysis of the grid 2 Wind speed (m/ s) expansion program

3 6 9 Source: 3Tier 1. Rampion COD is expected to be 2018, while all other projects have their planned COD between 2019 – 2024 65 2. Competitive Renewables Energy Zones (CREZ): Turning the Grandview site, among other areas, into a large site suitable for onshore wind installation Renewables

O&M case study – onshore wind example

O&M costs per MW decreasing1 Selected O&M improvement initiatives

-1500 bps -200 bps -200 bps  Spares strategy/ framework: Global gearbox agreement, own purchase of consumables 100% 85% 83% 81%  Predictive maintenance: Retrofitted with condition monitoring system

 Smart maintenance: Self-hoist crane concept

 O&M service concept: Previous mixed/ hybrid 2012 2013 2014 2015 team approach replaced by self-perform approach3

Availability increasing − Reduction of labor costs

98.8% − No extra labour and service costs in case of 98.2% 97.8% repair/ emergency − Full lever and immediate implementation of improvements as sites are under E.ON’s sole control N/A2 2012 2013 2014 2015

1. Example of single onshore wind plant operated by E.ON. O&M costs per MW in USD nominal 2. 2012 data recorded as time-based availability, hence not directly comparable with the energetic availability recorded in the following years 66 3. Mixed/ hybrid: E.ON Renewables team (EC&R) and OEM/ 3rd party as joint team with same tasks/ Self-perform: self-performed O&M managed by EC&R for high value work Renewables

Partnering and third party services

Partnering Third Party Services

 Monetizing part of our development  Full scale operations, maintenance, asset pipeline and operating asset portfolio and energy management services through establishing long-term partnerships  Emergence of new financial players and small/ midsized wind farm owners without  Increased financial flexibility and in-house technical competencies diversified portfolio  Leveraging global experience to manage  Economies of scale, further development risks on customer’s behalf of E.ON capabilities and of relationships with long-term valuable partners  Asset-light business model and economies of scale  Complementary capabilities, allowing to reduce LCOE and risks  Natural and complementary business model to partnering  Shared construction & operational risks and smoother earnings profile

 Additional income as construction manager and operator of the sites

67 Renewables

PV projects & initiatives

Key facts Capacity built1

MW  PV project delivery experience of >150 11 152 MW (14 projects), including development 49 and construction 92  Current geographical focus in US

 Vast majority of the projects delivered on time and on budget US Italy France Total  In the past, focus on build to sell Recent projects (built & sold)  Highly standardized development and Alamo engineering to ensure end-to-end process Size: 24 MW excellence and off-the-shelf PV project DC COD: May ’15 delivery Buyer: Dominion  Professional energy marketing enables Maricopa West participation in tenders and requests for Size: 28 MW proposals DC COD: Nov ’15 Buyer: Dominion

68 1. Until end 2015 Agenda

1. Group overview Strategic partnership Enerjisa PreussenElektra 2. Financials 3. Core activities Energy Networks Customer Solutions Renewables 4. IR Calendar and contacts E.ON Investor Relations contact

Florian Floßmann T+49 (201) 184 28 33 Head of Investor Relations [email protected]

Alexander Karnick T+49 (201) 184 28 38 Vice President Investor Relations [email protected]

Dr. Stephan Schönefuß T +49 (201) 184 28 22 Manager Investor Relations [email protected]

Martina Burger T +49 (201) 184 28 07 Manager Investor Relations [email protected]

70 Reporting calendar & important links

Reporting calendar

May 11, 2016 Interim Report I: January – March 2016

June 8, 2016 2016 Annual Shareholders Meeting

August 10, 2016 Interim Report II: January – June 2016

November 9, 2016 Interim Report III: January – December 2016

Important links

Capital Market Story http://www.eon.com/en/investors/presentations/capital-market-story.html

Other Presentations http://www.eon.com/en/investors/presentations/special-topics.html

Annual Reports http://www.eon.com/en/about-us/publications/annual-report.html

Interim Reports http://www.eon.com/en/about-us/publications/interim-report.html

Facts & Figures http://www.eon.com/en/about-us/publications/facts-and-figures.html

Creditor Relations http://www.eon.com/en/investors/presentations/bonds.html

71