Group equity story March 2012. E.ON Cleaner & better energy

Group equity story March 2012 E.ON Cleaner & better energy

Key drivers of E.ON s transformation Five key drivers Europe Focused & synergistic positioning Investment Less capital, more value Performance Efficiency & effective organization Cleaner & better energy Outside Europe Targeted expansion 1 Divest noncore assets 2 Safeguard financial strength 3 Expand in targeted growth areas 4 Increase efficiency, improve organization 5 Improve capital management Position E.ON for the future 2

1 Divest noncore assets Disposal target and delivery ~ 15bn ~ 9.5bn Pending 1 ~ 0.4bn Closed 2011 ~ 6.5bn Transactions Key transactions Central Networks for 4.8bn EV 3.5% stake in Gazprom for 3.4bn Italian gas distribution network for 0.3bn EV 40% stake in HSE for 0.3bn 10 other transactions for ~ 0.7bn: 10% in Stadtwerke Karlsruhe, 20% in Stadtwerke Duisburg, Robin Rigg OFTO, E.ON Bulgaria, etc Disposal target end 2013 Disposals as per March 2012 Closed 2010 ~ 2.6bn Potential disposal candidates OGE (German gas transmission network) E.ON EnergyfromWaste E.ON Westfalen Weser Divested broad range of assets at attractive conditions; simplify Group 1. Signed but not yet closed 3

2 Safeguard financial strength Debt significantly reduced 45 10 28 18 36 bn Financial net debt Economic net debt Comfortable liquidity position Strong liquidity position 11.9bn of liquid funds & noncurrent securities Undrawn 6.0bn revolving credit facility 10bn + $10bn commercial paper programs 2009A 2011A No nearterm refinancing needs: upcoming bond maturities do not require funding activities in 2012 3.9x 3.4x Debt factor <3.0x With 1.5bn negative oneoff Without 1.5bn negative oneoff Longterm and wellbalanced debt maturity profile Effective duration of issued bonds: 6.6 years 2011A Target Regaining financial flexibility 4

3 Expansion: Example outside Europe (I) Brazil first new region 20102020 projected demand growth up to 5% p.a. GW 80 60 40 20 0 1990 1995 2000 2005 2010 2015e 2020e Actual Projected Growth potential and risk/return profile Well diversified economy with strong growth across many sectors, sustainable demographics, and stable political system Brazilian power demand is expected to grow at about same rate as GDP for next few years Excellent energy management system: Longterm generation planning from regulator allows attractive margins to deliver new capacity In PPA framework, commodity price risk and volume risk managed at system level Passthrough of cost to consumers systematically done, PPAs honored Attractive growth at measured risk 5

3 Expansion: Example outside Europe (II) Assets brought into JV MPX assets outside JV Power plants in operation (24 MW) Power plants in execution (3 GW) Paranaiba Basin gas fields Seival coal mine Castillia TPP (Chile) 2.1 GW coal 100% MPX Seival & Sul TPP 1.3 GW coal 100% MPX Parnaiba TPP 2.2 GW gas 70% MPX Superport Açu project 2.1 GW coal 3.3 GW gas 100% MPX Agreement with MPX E.ON will acquire 10% of MPX through ~ 350m capital increase E.ON will form 50% JV with MPX MPX assets brought into JV 50% of interest in 11 GW of current projects under development E.ON interest 3.4 GW 100% of future projects MPX assets kept outside JV 24 MW in operation and 3 GW of projects in execution E.ON interest 0.3 GW Stakes in coal mine and gas fields Uniquely advantageous fuel supply providing competitive edge in PPA auctions Agreement with MPX marks first step in strategy execution outside Europe 6

3 Expansion: Example outside Europe (III) Entry strategy Focus on conventional and on renewable generation Agreement with MPX Economic interest in 3.7 GW of conventional power plant projects Clear ambition to expand in renewables Highly disciplined investment approach focused on organic development Limited upfront investment to acquire 10% of MPX Large project pipeline in JV Cooperate with blue chip local partner to combine own expertise with local market knowhow Limit commodity exposure through business model design MPX is a division of the Eike Batista s EBX Group, with businesses in power generation, coal mining and natural gas E&P in South America In PPA framework, system carries commodity price and volume risks Generator manages remaining operational risks Agreement with MPX fulfills all criteria of announced entry strategy 7

4 Increase efficiency, improve organization Controllable cost target bn Progress Breakdown of cost reductions ~10.9 >2 ~9.5 Procurement ~30% Operations ~40% 2011 controllable costs Cost inflation Cost reductions 2015 controllable costs Support functions & Overhead ~30% Target of reducing controllable costs to 9.5bn in 2015 Cost reductions to also compensate for cost inflation 50+ individual projects launched Not only cost savings, but also better and faster decision making Framework agreement with German labor unions reached in January E.ON 2.0 program: implementation now in full swing 8

5 Improve capital management A Increase return requirements C Ensure attractive dividend payouts Spread between hurdle rates and cost of capital B 2.5% 2.0% 1.5% 1.5% 1.0% 2010 2011 Change business approach 3.0% Infrastructure Most other activities E&P and wind offshore per share 1.00 1 1.10 1.10 Renewables: Build Operate Share approach Rotate capital faster Offer worldclass O&M services Outside Europe: Partnering Combine knowhow of both partners Expand investment opportunities by sharing capex 2011A 2012E 2013E Disciplined capital management drives long term performance 1. Proposed to the AGM of May 3rd, 2012 9

Summary: Deliver results Expected earnings development 20112013 EPS growth bn 11.612.3 2011A2015E underlying EPS CAGR of more than 10% 9.3 9.610.2 2.02.3 2.5 2.32.7 3.23.7 1.31 2011A 2012E 2013E 2011A 2015E EBITDA Underlying net income Underlying EPS ( per share) Earnings growth post 2011 10

Backup Charts Themes 1227 Financial targets 1220 Performance 21 Nuclear phase out 2227 Group key financials 28 FY 2011 financial highlights 2932 Balance sheet 3338 Hedging 39 Investor relations contact 4041

Financial targets 2012/2013 Outlook overview In billion 2012 2013 EBITDA 1 : 9.6 10.2 Underlying net income 1 : 2.3 2.7 Underlying EPS 1 : 1.2 1.4 /share Dividend: 1.10 /share EBITDA 1 : 11.6 12.3 Underlying net income 1 : 3.2 3.7 Underlying EPS 1 : 1.7 2.0 /share Dividend: 1.10 /share Scope basis for 2012/2013 Disposal proceeds 2013 EBITDA dilution Planned (as per Nov. 2010) 15.0 1.5 2.0 Achieved (as per Aug. 2011) ~9.1 ~0.9 Open (as per Aug. 2011) ~5.9 ~0.8 Current guidance contains scope for achieved disposal as per August 2011 Scope adjustment planned post next major disposal deal signing Full dilution impact of ~ 0.8bn from remaining disposals does not consider reinvestments 1. Adjusted for extraordinary effects 12

Financial targets EBITDA 1 outlook FY 2012 by reporting segment Old reporting structure 2 In million 2011A 2012 vs. 2011 Main drivers Generation 2,114 above Mainly absence of nuclear oneoff Renewables 1,459 below Lower market based internal transfer prices Gas 1,533 below Mainly absence of oneoffs in other/consolidation Trading 631 above Lower spread between transfer & achieved price Germany 2,421 in line Other EU countries 2,259 below Mainly deconsolidation of UK central networks Russia 553 above Full year contribution from new capacities Group Management/Other 415 above Total 9,292 9.6 10.2 1. Adjusted for extraordinary effects 2. Outlook according to new structure effective from Q1 2012 onwards on page 37 of this presentation 13

Financial targets Planned change in group structure as per Q1 2012 2011 Group Management New Build & Generation Renewables Gas Trading Germany Technology 1 Other EU countries Russia Support functions 1 Global units Regional units Support functions 2012 Group Management Generation Renewables Optimization& Trading Exploration& Production New Build & Technology 1 Germany Other EU countries Russia Support functions 1 Prop. Trading Optimization Transmission/ Shareholdings/ Other 1. Not a reporting segment. Global units Regional units Support functions 14

Financial targets EBITDA 1 outlook FY 2012 by reporting segment New reporting structure (from Q1 2012 onwards) In million 2011A 2012E Main drivers Generation 2,114 above Mainly absence of nuclear oneoff Renewables 1,459 below Lower market based internal transfer prices Optimization and trading 160 below Margin pressure in power and gas markets Exploration and production 727 above Higher volumes & prices Germany 2,457 inline Other EU countries 2,259 below Mainly deconsolidation of UK central networks Russia 553 above Full year contribution from new capacities Group Management/Other 436 above Total 9,293 1. Adjusted for extraordinary effects 15

Financial targets Important drivers for 2012 vs. 2011 EBITDA 1 development In billion EBITDA 1 2011 9.3 Positives Absence of nuclear one off Higher E&P earnings Higher volumes in Russian power Negatives Lower power earnings (spread and outright) Higher nuclear tax Several deconsolidation effects (mainly UK Central Networks) Lower retail margins (mainly UK) Absense of positve oneoffs in gas (other/consolidation) EBITDA 1 2012 Outlook range 9.6 10.2 Absence of nuclear one off key positive earnings driver, lower power earnings biggest negative 1. Adjusted for extraordinary effects 16

Financial targets Important drivers for 2013 vs. 2012 EBITDA 1 development In billion EBITDA 2012 1 Outlook range 9.6 10.2 Positives Impact of cost cutting (post inflation) Higher E&P earnings Higher gas supply and sales earnings Higher renewables volumes and prices Higher power prices in Russia Negatives Absence of free CO2 allocation Slightly lower power earnings EBITDA 2013 1 Outlook range 11.6 12.3 2013 guidance unchanged 1. Adjusted for extraordinary effects 17

Financial targets From EBITDA 1 to underlying EPS 1 (20112015) In billion 2011A 2012E 2013E 2015E 3 EBITDA 1 9.3 9.6 10.2 11.612.3 12.5 13.0 Depreciation 3.9 ~3.9 ~4.4 Adj. interest expense 1.8 ~1.9 ~1.9 Taxes 2 0.8 ~1.2 ~1.7 Minorities 0.4 ~0.4 ~0.5 Underlying net income 1 2.5 2.3 2.7 3.2 3.7 Underlying EPS ( /share) 1 1.3 1.2 1.4 1.7 2.0 2.0 2.3 More than 10% EPS CAGR between 2011 and 2015 expected 1. Adjusted for extraordinary effects 2. The future tax rate is significantly impacted by external factors such as regional tax regimes, local tax laws etc. and therefore is indicative only 3. Fully diluted; no reinvestments assumed 18

Financial targets Key assumptions for commodity business Key price assumptions Volume assumptions (2010/2013) 1 Assumed average achieved prices outright generation TWh Nuclear Hydro CE market ( /MWh) Nordic market ( /MWh) CE 2010A 55 5 2013E Old 2 42 5 58 55 47 43 2013E New 42 5 2013 Old 2 Oil ($/barrel) 2013 New 3 2013 2013 Old 2 New 3 Coal (API#2) ($/ton) Nordic 2010A 2013E Old 2 2013E New 19 19 19 8 8 8 Coal 21 30 31 Gas 11 10 10 3 3 2 109 105 2013 Old 2 2013 New 3 132 112 2013 2013 Old 2 New 3 UK 2010A 2013E Old 2 2013E New 14 11 13 15 19 15 CO 2 ( /ton) Gas TTF ( /MWh) 19 2013 Old 2 7 2013 New 3 28 25 2013 2013 Old 2 New 3 Assumed prices 1. Only volumes marketed via EET for CE, UK and Nordic. (excluding contract steered power plants; mainly coal in Germany e.g. Scholven, Datteln, etc.). Volume data as of 31.12.2011 2. As per CMD in August 2011 3. Open positions marked to market per 18. January 19

Financial targets CAPEX plan 20112014 E.ON Group capex 1 E.ON Group capex split 1 bn bn 8 ~7.0 ~6.5 ~6.5 ~7.0 ~5.7 ~5.7 ~6.2 6 ~6.2 4 2 0 2011A 2012E 2013E 2014E Maintenance Growth / Replacement 2011A 2012E 2013E 2014E Generation Renewables Global Gas Regional Units Moving towards a sustainable capex level 1. Investments (casheffective) before Portfolio and E.ON 2.0 measures 20

Performance Performance Controllable costs Definition of controllable costs Transition from income statement to controllable costs FY 2010 Controllable costs are those costs that are under control of operational management Only costs above EBITDA line bn Cost of materials Total 73.6 Controllable costs ~4 Comment Excludes fuel and CO2 emission costs Excludes purchasing costs of power and gas 36% Controllable costs consist of Part of cost of materials Most of personnel costs Other operating income & expenses Personnel costs Other operating income & expenses, net 5.3 2.4 ~5 ~2 Excludes restructuring expenses and other nonoperating costs Includes several items such as marketing, IT, purchased services 46% Total 76.5 ~11 18% Reduction of controllable costs as key value lever 1. As communicated during Capital Market Day Nov. 2010 21

German nuclear Accelerated nuclear phaseout: Key effects 1 Oneoff effects within and below adj. EBITDA Full year effects 2011 2013 bn 1H 2011E bn 2011E 2012E 2013E Oneoff effects within adj. EBITDA 1.5 Capacity loss (GW) 3.2 3.2 3.2 Oneoff effects below adj. EBITDA Depreciation: Writedown fixedassets in use (Isar 1 & Unterweser) Interest expense: Reversal interest charge renewable energy fund Nonoperating earnings Impairment assets under construction Isar 1 & Unterweser Impairment shareholdings Brunsbüttel & Krümmel 0.2 0.1 +0.1 0.2 0.1 0.1 Production loss (TWh) Recurring effects Adj. EBITDA Foregone gross margin (incl. avoided nuclear tax) Oneoff effects Adj. EBITDA Writedown nuclear fuel/spare parts Isar 1 & Unterweser Additions to nuclear provisions Isar 1 & Unterweser Additions to other provisions (Brunsbüttel & Krümmel) 12 0.4 1.5 0.2 0.3 0.6 23 0.20.3 23 0.20.3 Additions to other provisions (Isar 1 & Unterweser) 0.4 Nuclear tax 0.6 0.7 0.8 0.7 0.8 Significant negative effects in 2011 1. Disclaimer: Figures only reflect adjusted EBITDA & below EBITDA effects and do not show damage for E.ON 22

German nuclear E.ON s nuclear fleet in Germany Remaining lifetime 1 in TWH Startup date 2 Capacity net (MW) E.ON share (%) Total output FY 2010 Remaining rest volumes December 31, 2010 Shutdown date (31 December of the respective year, except for 2011) Isar 1 1979 878 100 6.3 4 2011 Unterweser 1979 1,345 100 10.7 14 2011 Brunsbüttel 1977 771 33.3 0 11 2011 Krümmel 1984 1,346 50 0 88 2011 Grafenrheinfeld 1982 1,275 100 7.5 42 2015 Gundremmingen B 1984 1,284 25 9.5 50 2017 Brokdorf 1986 1,410 80 11.4 94 2021 Grohnde 1985 1,360 83.3 10.8 82 2021 Gundremmingen C 1985 1,288 25 10.4 59 2021 Emsland 1988 1,329 12.5 11.0 109 2022 Isar 2 1988 1,410 75 11.4 105 2022 1. Source: Bundesamt für Strahlenschutz, Tabelle der erzeugten Strommengen und verbleibenden Reststrommengen 2. Start of commercial production 23

German nuclear Status nuclear provisions 2010 & 2011 Balance sheet m FY 2011 FY 2010 Nuclear provisions Germany Decommissioning Disposal of nuclear fuel rods and operational waste Advance payments Sweden Decommissioning Disposal of nuclear fuel rods and operational waste 14,803 13,145 9,478 4,595 928 2,120 716 1,404 14,278 12,231 8,420 4,671 860 2,047 664 1,383 Financial receivables & other assets: claim on Swedish nuclear waste fund 1,595 1,498 24

German nuclear Decommissioning and waste management provisions Schematic profile cash out after shut down Schematic profile of decommissioning and waste management cash out for typical NPP after shut down m/gw in real terms 100 80 60 40 20 0 0 10 20 30 40 50 Years after shutdown Waste management Cooldown phase Dismantling phase Comments All costs after shutdown covered by decommissioning and waste management provisions Decommissioning (including final storage) is about 1.5bn (nominal) Waste Management is about 1.0bn nominal Main components of the provisions Cooldown phase: ~7 years, relatively predictable, as costs structure similar to plant in operation but on lower level Dismantling phase: ~12 years, estimated every few years by independent appraiser (Nuklear Ingenieur Service, NIS) Waste management costs: main drivers are costs for containers, conditioning, interim and final storage Cooldown phase weighs heavily in total of decommissioning costs 25

German nuclear From costs to provision Schematic nuclear provision for a typical NPP m/gw 160 140 120 100 80 60 40 20 0 30 20 10 0 10 20 30 40 50 Years before/after shutdown 1600 Decommissioning 1400 costs in nominal terms 1200 1000 Decommissioning costs in real 800 terms 600 400 200 0 Nuclear provision in real terms Nuclear provision in nominal terms At any point in time, decommissioning provisions are simply the present value of the future cash flows related to decommissioning Accountingwise, decommissioning provisions are thus similar to a bundle of zerocoupon obligations Real problem is to estimate future cash outflows: as they stretch over long periods into the future, they are heavily impacted by inflation Estimating nuclear provisions in practice 1. Starting point: estimate of decommissioning costs at current prices (current cost estimate) 2. Current cost estimate is inflated at the escalation rate to the moment of effective cash outflow (shown below as all taking place in a single year) to estimate the effective cash outflow at future prices 3. Estimated future cash outflows discounted back to the present at the appropriate discount rate to calculate the nuclear provision 4 key parameters: current cost estimate, timing of cash flows, escalation rate, and discount rate 1 2 3 Current cost estimate Nuclear provision Future cash outflow Cost escalation Discounting Main difficulty is to estimate decommissioning outflows over very long time frames 26

German nuclear Sensitivity of nuclear provisions Increase in current cost estimate 1 2 3 4 Decommissioning moved forward 3 4 1 2 Old nuclear provision 1. Escalating current cost estimate to obtain future cash outflow estimate 2. Discounting future cash flow estimate back to present to obtain nuclear provision New nuclear provision Current cost estimate 50% higher Escalation rate, discount rate and timing of future cash flow unchanged 3. Escalating higher current cost estimate yields higher future cash outflow estimate 4. Discounting higher future cash flow estimate back to present gives higher nuclear provision Nuclear provisions change in same proportion as current cost estimates: 50% increase in current cost estimate leads to 50% increase of nuclear provision Old nuclear provision 1. Escalating current cost estimate to obtain future cash outflow estimate 2. Discounting future cash flow estimate back to present to obtain nuclear provision New nuclear provision Timing of decommissioning cash flows moved forward Current cost estimate, escalation rate and discount rate unchanged 3. Escalating current cost estimate over fewer years leads to lower future cash flows 4. Discounting lower future cash flow estimate back to present over fewer years gives slightly higher nuclear provision Earlier decommissioning leads to only slightly higher nuclear provision because discounting over fewer years is partially offset by escalation over fewer years 1 Old / New current cost estimate Old / New future cash flow estimate Old / New nuclear provision 1. If escalation rate is lower than discount rate, which is normally the case. Old / New escalation from current cost estimate to future cash flow estimate Old / New discounting from future cash flow estimate to nuclear provision 27

Key financials E.ON Group history of chosen key figures 1 in millions 2004 2005 2006 2007 2008 2009 2010 2011 Sales 42,150 51,616 64,091 68,731 86,753 79,974 92,863 112,954 EBITDA 2 9,664 10,194 11,724 12,450 13,385 12,975 13,346 9,293 EBIT 2 6,747 7,293 8,356 9,208 9,878 9,291 9,454 5,438 ROCE/ROACE 3 (in %) 11.5 12.2 13.8 14.5 12.9 12.2 11.9 8.4 Cost of capital pre tax (in %) 9.0 9.0 9.0 9.1 9.1 9.1 8.3 8.3 Value added 1,477 1,920 2,916 3,417 2,902 2,362 2,864 90 Underlying EPS ( ) n.a. n.a. 2.37 2.62 3.01 2.79 2.56 1.31 Dividend per share ( ) 0.78 0.92 1.12 1.37 1.50 1.50 1.50 1.00 1. Adjusted for discontinued operations; figures prior to 2006 calculated according to U.S.GAAP 2. Adjusted for extraordinary effects 3. From 2011 onwards 28

Highlights FY 2011 E.ON Group Financial highlights In million Sales 112,954 92,863 +22 EBITDA 1 9,293 13,346 30 EBIT 1 5,438 9,454 42 Underlying net income 1 2,501 4,882 49 Operating cash flow 10,614 Investments 6,524 8,286 21 Economic net debt 2 36,385 37,701 +1,316 2011 6,610 2010 +/ % 38 1. Adjusted for extraordinary effects 2. Change in absolute terms 29

Highlights FY 2011 E.ON Group EBITDA 1 and EBIT 1 by segments In million 2011 EBITDA 1 EBIT 1 2010 +/% 2011 2010 +/ % Generation 2,114 3,757 44 1,128 2,767 59 Renewables 1,459 1,207 +21 1,088 880 +24 Gas 1,533 1,975 22 997 1,415 30 Trading 631 1,205 642 1,196 Germany 2,421 2,463 2 1,470 1,541 5 Other EU countries 2,259 2,583 13 1,491 1,713 13 Russia 553 377 +47 398 250 +59 Group Management / Other 415 221 492 308 Group total 9,293 13,346 30 5,438 9,454 42 1. Adjusted for extraordinary effects 30

Highlights FY 2011 Key drivers of group EBITDA 1 2011 vs. 2010 Full year 2011 in billion 01.01.2010 31.12.2010 13.3 2.5 EBITDA 2010 Nuclear: Nuclear phaseout and fuel tax +9.9 01.01.2011 31.12.2011 1.0 0.7 0.5 0.3 + 0.1 + 0.1 + 0.1 + 0.2 + 0.2 + 0.4 0.1 9.3 Power portfolio: Price and volume effects Gas: Gross margin Portfolio effects: Central Networks, E.ON Rete Germany: Distribution grid Upstream: Price and volume effects EC&R: Higher volumes Trading: Proprietary trading Region Czech: RES compensation revenues Russia Group: Higher efficiency (Performtowin) Others EBITDA 2011 1. Adjusted for extraordinary effects 31

Highlights FY 2011 Operating cash flow reconciliation Full year 2011 in billion 01.01.10 31.12.10 10.6 FY 2010 operating cash flow 4.0 EBITDA + 1.1 0.2 Noncasheffective EBITDA UK/Germany: Pension funding +6,738 0.3 0.2 Global Gas: Increase in working capital Trading: Working capital increase from higher volumes 0.2 0.3 0.2 0.1 + 0.7 Renewables: US cash grants Other EUcountries: Increase in working capital Portfolio effects: a.o. Central Networks Group: Higher interest payments Group: Lower tax payments 01.01.11 31.12.11 0.3 6.6 Others FY 2011 operating cash flow 32

Balance sheet E.ON Group Economic net debt In million Liquid funds Noncurrent securities Total liquid funds and noncurrent securities Financial liabilities to banks and third parties Financial liabilities resulting from interests in associated companies and other shareholdings Total financial liabilities Net financial position Fair value of currency derivatives used for financing transactions 1 Provisions for pensions Asset retirement obligations Less prepayments to Swedish nuclear fund Economic net debt 2011 7,020 4,904 11,924 28,490 1,424 29,914 17,990 524 3,245 17,269 1,595 36,385 2010 8,273 3,903 12,176 31,799 692 32,491 20,315 334 3,250 15,968 1,498 37,701 1. Net figure; does not include transactions relating to our operating business or asset management 33

Balance sheet Change of financial liabilities 2010 and 2011 bn Reduction of total financial liabilities per period Commercial paper 2011 Regular repayments 2.1 Repayments prior to maturity 1 Changes of financial liabilities to related companies 0.7 Other effects 2 2.6 2.4 0.9 0.3 2010 5.3 3.5 1.1 1.5 0.8 Significant reduction of financial liabilities during 2010 and 2011 achieved 1. Includes bond repurchases ( 1.8 bn) and repayment of promissory notes ( 0.6 bn) 2. Including effects from disposals and currency effects 34

Balance sheet E.ON s interest rate policy Key elements of E.ON s interest rate policy E.ON's business model is capital intensive and has a very longterm investment horizon As E.ON is not a cyclical company, funding at variable rates does not provide a hedge for business risks Risk capital is mainly allocated to commodity risks As a consequence, we strive to minimize interest rate risks by implementing a high fixed portion of our funding Key figures (as of 31 December 2011; including use of interest derivatives) Average interest rate of gross debt (all currencies): 5.0% Share of financial liabilities with fixed interest rates: 94% Effective interest duration: 6.6 year 35

Balance sheet Financial liabilities of the E.ON Group in billion 31 Dec 2011 31 Dec 2010 Maturity profile (as of 31 Dec 2011) 3 Bonds 1 23.4 27.5 in EUR in GBP 13.3 5.0 16.6 5.5 bn 5,0 in USD 2.6 2.5 4,0 in CHF 1.3 1.6 3,0 in SEK 0.3 0.4 2,0 in JPY 0.8 0.7 1,0 other currencies Promissory notes Commercial Paper 0.1 0.8 0.9 0.2 1.4 0,0 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 EUR GBP USD CHF YEN Other Other liabilities 2 4.8 3.6 Total 29.9 32.5 1) Thereof bonds issued by segments: December 31, 2011: 0.3bn; Dec 31, 2010: 0.9bn 2) Thereof other financial liabilities of segments: December 31, 2011: 3.2bn; Dec 31, 2010: 2.9bn 3) Bonds and promissory notes issued by E.ON AG or E.ON International Finance B.V. (fully guaranteed by E.ON AG) 36

Balance sheet E.ON Group Detail on economic interest expense (net) Full year 2011 in million 2011 2010 Delta 11 / 10 Interest from financial assets/liabilities Interest cost from provisions for pensions and similar provisions 1 Accretion of provisions for retirement obligation and other provisions 1,058 144 807 1,435 167 778 +377 +24 29 Capitalised interests 2 312 316 4 Other 3 80 194 +114 Economic interest expense (net) 1,776 2,257 +482 1. Net of expected return on planassets 2. Borrowing costs that are directly attributable to the acquisition, construction or production of a qualified asset. Borrowing costs are interest and other costs incurred by an entity in connection with the borrowing of funds. (IRrate: 5%) 3. Includes mainly effects from market valuation of interest derivatives and interest cost from tax provisions. 37

Balance sheet Safeguarding financial strength Key measures and targets Secure solid single A rating: Adjustment of debt factor target to <3.0 Significant reduction of financial debt via use of disposal proceeds Reduced dividend payments Earnings improvement from efficiency measures Maintain balanced portfolio of stable versus merchant operations to support credit profile Debt significantly reduced 45 38 28 20 36 18 2011A 2009A 2010A 2011 High share of stable operations Quasiregulated and longterm contracted 10% Merchant business 50% bn Economic net debt Financial net debt 2011 EBITDA 1 split Regulated 40% 1. Adjusted for extraordinary effects 38

Hedging Hedging of E.ON s outright generation As of Dec 31, 2011 German, Benelux and French market 2011 2012 2013 2014 ~ 59 /MWh 1 ~ 54 /MWh 1 ~ 55 /MWh 1 ~ 55 /MWh 1 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Nordic market 2011 2012 2013 2014 ~ 43 /MWh 1 ~ 43 /MWh 1 ~ 44 /MWh 1 ~ 45 /MWh 1 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% = percentage band of generation hedged 1. Average realized price only relevant for the pure outright power position (Nuclear/Hydro) sold in the respective year 39

E.ON Investor Relations Contact Sascha Bibert Head of IR T+49 2 1145 795 42 sascha.bibert@eon.com Peter Blankenhorn Regions/Sales, SRI, Retail, T +49 2 1145 794 81 Facts & Figures peter.blankenhorn@eon.com François Poullet Generation, Gas T +49 2 1145 793 32 francois.poullet@eon.com What can we do to help you? Marc Koebernick Renewables, Trading T +49 2 1145 792 39 marc.koebernick@eon.com Dr. Stephan Schönefuß Politics & regulation, Regions/Distribution T +49 2 1145 7948 08 stephan.schoenefuss@eon.com Aleksandr Aksenov Outside Europe, Russia T +49 2 1145 795 54 aleksandr.aksenov@eon.com Carmen Schneider Technology & Innovation, Roadshow planning & management, T +49 2 1145 793 45 Shareholder ID & Targeting carmen.schneider@eon.com 40

E.ON IR Reporting calendar & important links Reporting calendar Date May 3, 2012 May 4, 2012 May 9, 2012 August 13, 2012 November 13, 2012 March 13, 2013 Event AGM 2012 Dividend payment Interim Report I: January March 2012 Interim Report II: January June 2012 Interim Report III: January September 2012 Annual report 2012 Location Essen Düsseldorf Düsseldorf Düsseldorf Düsseldorf Important links Content Equity Story Segment Stories Annual Report Interim Reports Facts & Figures Link http://www.eon.com/en/investors/26658.jsp http://www.eon.com/en/investors/42341.jsp http://www.eon.com/en/corporate/19886.jsp http://www.eon.com/en/corporate/1022.jsp http://www.eon.com/en/corporate/1029.jsp 41

This presentation may contain forwardlooking statements based on current assumptions and forecasts made by E.ON Group management and other information currently available to E.ON. Various known and unknown risks, uncertainties and other factors could lead to material differences between the actual future results, financial situation, development or performance of the company and the estimates given here. E.ON AG does not intend, and does not assume any liability whatsoever, to update these forwardlooking statements or to conform them to future events or developments. 42